Vermilion Energy Inc. Announces Results for the Three and Nine Months Ended September 30, 2015

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Nov 09, 2015, 02:10 ET

CALGARY, Nov. 9, 2015 /CNW/ - Vermilion Energy Inc. ("Vermilion", "We", "Our", "Us" or the "Company") (TSX, NYSE: VET) is pleased to report operating and unaudited financial results for the three and nine months ended September 30, 2015.

HIGHLIGHTS

Record quarterly production of 56,280 boe/d for Q3 2015 exceeded prior quarter production of 51,831 boe/d by 9%. This quarter-over-quarter increase was primarily attributable to higher production in the Netherlands due to recent drilling success, with additional contributions from the Canadian Mannville drilling program and increased Australian oil production. Canadian third-party facility restrictions negatively impacted average production by approximately 900 boe/d during Q3.
Fund flows from operations ("FFO")⁽¹⁾ for Q3 2015 of $129.4 million ($1.17/basic share) were in-line with $129.5 million ($1.18/basic share) for the prior quarter despite a quarter-over-quarter decrease in oil prices of nearly 20%. Production growth in advantageously-priced European natural gas enabled us to deliver consistent financial results, demonstrating a key benefit of our international diversification.
Vermilion was recently named to the CDP Climate Disclosure Leadership Index ("CDLI"), recognizing the depth and quality of our climate-related disclosure as compared to the 200 largest companies listed on the TSX. CDP (formerly Carbon Disclosure Project), is a global, not-for-profit organization that manages the world's only global environmental disclosure system. To be named to the CDLI, a company must have a disclosure score within the top 10% of surveyed companies. Vermilion has voluntarily reported to CDP since 2012. We believe that by measuring and understanding our current environmental profile, we can adapt our business strategy to operate in an even more environmentally and socially sustainable manner in the future.
Vermilion is pleased to confirm that the Irish Environmental Protection Agency issued its final determination in support of the Corrib Industrial Emissions License on October 8, 2015. Previously, on September 1, 2015 the operator, Shell E&P Ireland Limited declared the project ready for service. As a result, the sole remaining requirement prior to commencing gas production at Corrib is the receipt of Ministerial Consent from Ireland's Department of Communications, Energy and Natural Resources. Following start-up, production levels at Corrib are expected to rise over a period of approximately six months to a peak rate estimated at 58 mmcf/d (9,700 boe/d), net to Vermilion by mid-2016. While the final regulatory approvals have taken longer than we originally expected, we believe that the regulatory process for Corrib is near completion, and still expect to achieve first production in approximately mid-Q4 2015. We believe that our ability to maintain our 2015 production guidance (originally set in March 2014) and achieve more than 10% annual production growth, despite the later-than-expected start-up of Corrib and 30% lower year-over-year capital expenditures, is indicative of the operational strength of our Company.
Responding to the continued weakness in oil prices, we expect that our exploration and development ("E&D") capital program will be approximately $350 million in 2016. This would represent a year-over-year reduction of more than 25% from our forecasted 2015 E&D capital expenditures of $485 million and nearly 50% from our E&D capital program in 2014. At current prices, we would expect to be able to more than fully fund our 2016 capital expenditures and net dividends from fund flows from operations. We are maintaining the 2016 production guidance of 63,000 to 65,000 boe/d that we set in March 2014. Production in this range would represent year-over-year growth of 14% to 18% as compared to 2015, largely weighted to European natural gas. We plan to provide detailed 2016 capital expenditure guidance prior to year-end 2015.
Our Profitability Enhancement Program ("PEP") initiative continues to provide significant benefits in this challenging industry environment. Prior installments of PEP achieved strong results in both the 1998 industry downturn and the financial crisis of 2008-2009. We expect that our third installment of PEP will result in cost savings related to capital spending, operating expense and G&A expenditures estimated at between $70 and $80 million for full-year 2015.

⁽¹⁾	Additional GAAP Financial Measure. Please see the "Additional and Non-GAAP Financial Measures" section of Management's Discussion and Analysis.

Conference Call and Audio Webcast Details

Vermilion will discuss these results in a conference call to be held on Monday, November 9, 2015 at 9:00 AM MST (11:00 AM EST). To participate, you may call 1-888-231-8191 (Canada and US Toll Free) or 1-647-427-7450 (International and Toronto Area). The conference call will also be available on replay by calling 1-855-859-2056 using conference ID number 49495111. The replay will be available until midnight mountain time on November 16, 2015.

You may also listen to the audio webcast by going to http://event.on24.com/r.htm?e=1056685&s=1&k=8F525422649C891C089BC59110D715CC or visit Vermilion's website at www.vermilionenergy.com/ir/eventspresentations.cfm.

HIGHLIGHTS

		Three Months Ended			Nine Months Ended
($M except as indicated)		Sep 30,	Jun 30,	Sep 30,	Sep 30,	Sep 30,
Financial		2015	2015	2014	2015	2014
Petroleum and natural gas sales		245,051	264,331	344,688	705,267	1,113,555
Fund flows from operations⁽¹⁾		129,435	129,496	197,898	379,726	619,337
	Fund flows from operations ($/basic share)	1.17	1.18	1.85	3.48	5.90
	Fund flows from operations ($/diluted share)	1.16	1.17	1.83	3.44	5.81
Net earnings (loss)		(83,310)	6,813	53,903	(75,222)	210,684
	Net earnings (loss) ($/basic share)	(0.76)	0.06	0.50	(0.69)	2.01
Capital expenditures		93,381	90,173	190,033	357,865	521,481
Acquisitions		22,155	480	40,847	22,670	600,213
Asset retirement obligations settled		2,123	1,218	4,677	6,448	9,709
Cash dividends ($/share)		0.645	0.645	0.645	1.935	1.935
Dividends declared		71,244	70,976	68,896	211,610	203,613
	% of fund flows from operations	55%	55%	35%	56%	33%
Net dividends⁽¹⁾		26,654	28,675	48,480	103,341	145,163
	% of fund flows from operations	21%	22%	24%	27%	23%
Payout⁽¹⁾		122,158	120,066	243,190	467,654	676,353
	% of fund flows from operations	94%	93%	123%	123%	109%
	% of fund flows from operations (excluding the Corrib project)	77%	76%	107%	107%	97%
Net debt⁽¹⁾		1,363,043	1,377,902	1,243,438	1,363,043	1,243,438
Ratio of net debt to annualized fund flows from operations⁽¹⁾		2.6	2.7	1.6	2.7	1.5
Operational
Production
	Crude oil (bbls/d)	28,164	28,916	29,147	28,420	28,890
	NGLs (bbls/d)	4,622	3,867	2,354	3,849	2,463
	Natural gas (mmcf/d)	140.97	114.29	110.52	123.51	109.33
	Total (boe/d)	56,280	51,831	49,920	52,854	49,574
Average realized prices
	Crude oil and NGLs ($/bbl)	56.57	68.90	102.49	61.48	108.02
	Natural gas ($/mcf)	5.36	4.86	5.74	5.18	6.60
Production mix (% of production)
	% priced with reference to WTI	24%	27%	28%	26%	27%
	% priced with reference to AECO	22%	21%	18%	21%	18%
	% priced with reference to TTF	20%	16%	18%	18%	18%
	% priced with reference to Dated Brent	34%	36%	36%	35%	37%
Netbacks ($/boe)⁽¹⁾
	Operating netback	32.25	36.89	54.25	33.55	58.95
	Fund flows from operations netback	24.58	26.76	44.08	26.64	46.02
	Operating expenses	10.99	12.12	12.53	11.25	12.81
Average reference prices
	WTI (US $/bbl)	46.43	57.94	97.17	51.00	99.61
	Edmonton Sweet index (US $/bbl)	43.01	55.08	89.24	46.64	92.17
	Dated Brent (US $/bbl)	50.26	61.92	101.85	55.39	106.57
	AECO ($/GJ)	2.75	2.52	3.81	2.62	4.56
	TTF ($/GJ)	8.04	7.94	7.26	8.08	8.41
Average foreign currency exchange rates
	CDN $/US $	1.31	1.23	1.09	1.26	1.09
	CDN $/Euro	1.46	1.36	1.44	1.40	1.48
Share information ('000s)
Shares outstanding - basic		110,818	109,806	106,921	110,818	106,921
Shares outstanding - diluted ⁽¹⁾		113,643	112,626	109,749	113,643	109,749
Weighted average shares outstanding - basic		110,293	109,319	106,768	109,052	104,891
Weighted average shares outstanding - diluted		111,193	110,746	108,290	110,433	106,582

⁽¹⁾	The above table includes additional GAAP and non-GAAP financial measures which may not be comparable to other companies. Please see the "ADDITIONAL AND NON-GAAP FINANCIAL MEASURES" section of Management's Discussion and Analysis.

DISCLAIMER

Certain statements included or incorporated by reference in this document may constitute forward looking statements or financial outlooks under applicable securities legislation. Such forward looking statements or information typically contain statements with words such as "anticipate", "believe", "expect", "plan", "intend", "estimate", "propose", or similar words suggesting future outcomes or statements regarding an outlook. Forward looking statements or information in this document may include, but are not limited to: capital expenditures; business strategies and objectives; operational and financial performance; estimated reserve quantities and the discounted present value of future net cash flows from such reserves; petroleum and natural gas sales; future production levels (including the timing thereof) and rates of average annual production growth; estimated contingent resources and prospective resources; exploration and development plans; acquisition and disposition plans and the timing thereof; operating and other expenses, including the payment and amount of future dividends; royalty and income tax rates; the timing of regulatory proceedings and approvals; and the timing of first commercial natural gas and the estimate of Vermilion's share of the expected natural gas production from the Corrib field.

Such forward looking statements or information are based on a number of assumptions all or any of which may prove to be incorrect. In addition to any other assumptions identified in this document, assumptions have been made regarding, among other things: the ability of Vermilion to obtain equipment, services and supplies in a timely manner to carry out its activities in Canada and internationally; the ability of Vermilion to market crude oil, natural gas liquids and natural gas successfully to current and new customers; the timing and costs of pipeline and storage facility construction and expansion and the ability to secure adequate product transportation; the timely receipt of required regulatory approvals; the ability of Vermilion to obtain financing on acceptable terms; foreign currency exchange rates and interest rates; future crude oil, natural gas liquids and natural gas prices; and management's expectations relating to the timing and results of exploration and development activities.

Although Vermilion believes that the expectations reflected in such forward looking statements or information are reasonable, undue reliance should not be placed on forward looking statements because Vermilion can give no assurance that such expectations will prove to be correct. Financial outlooks are provided for the purpose of understanding Vermilion's financial position and business objectives and the information may not be appropriate for other purposes. Forward looking statements or information are based on current expectations, estimates and projections that involve a number of risks and uncertainties which could cause actual results to differ materially from those anticipated by Vermilion and described in the forward looking statements or information. These risks and uncertainties include but are not limited to: the ability of management to execute its business plan; the risks of the oil and gas industry, both domestically and internationally, such as operational risks in exploring for, developing and producing crude oil, natural gas liquids and natural gas; risks and uncertainties involving geology of crude oil, natural gas liquids and natural gas deposits; risks inherent in Vermilion's marketing operations, including credit risk; the uncertainty of reserves estimates and reserves life and estimates of resources and associated expenditures; the uncertainty of estimates and projections relating to production and associated expenditures; potential delays or changes in plans with respect to exploration or development projects; Vermilion's ability to enter into or renew leases on acceptable terms; fluctuations in crude oil, natural gas liquids and natural gas prices, foreign currency exchange rates and interest rates; health, safety and environmental risks; uncertainties as to the availability and cost of financing; the ability of Vermilion to add production and reserves through exploration and development activities; the possibility that government policies or laws may change or governmental approvals may be delayed or withheld; uncertainty in amounts and timing of royalty payments; risks associated with existing and potential future law suits and regulatory actions against Vermilion; and other risks and uncertainties described elsewhere in this document or in Vermilion's other filings with Canadian securities regulatory authorities.

The forward looking statements or information contained in this document are made as of the date hereof and Vermilion undertakes no obligation to update publicly or revise any forward looking statements or information, whether as a result of new information, future events or otherwise, unless required by applicable securities laws.

All oil and natural gas reserve information contained in this document has been prepared and presented in accordance with National Instrument 51-101 Standards of Disclosure for Oil and Gas Activities. The actual crude oil and natural gas reserves and future production will be greater than or less than the estimates provided in this document. The estimated future net revenue from the production of crude oil and natural gas reserves does not represent the fair market value of these reserves.

Natural gas volumes have been converted on the basis of six thousand cubic feet of natural gas to one barrel of oil equivalent. Barrels of oil equivalent (boe) may be misleading, particularly if used in isolation. A boe conversion ratio of six thousand cubic feet to one barrel of oil is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead.

Financial data contained within this document are reported in Canadian dollars, unless otherwise stated.

ABBREVIATIONS

$M			thousand dollars
$MM			million dollars
AECO			the daily average benchmark price for natural gas at the AECO 'C' hub in southeast Alberta
bbl(s)			barrel(s)
bbls/d			barrels per day
bcf			billion cubic feet
boe			barrel of oil equivalent, including: crude oil, natural gas liquids and natural gas (converted on the basis of one boe for six mcf of natural gas)
boe/d			barrel of oil equivalent per day
GJ			gigajoules
HH			Henry Hub, a reference price paid for natural gas in US dollars at Erath, Louisiana
mbbls			thousand barrels
mboe			thousand barrel of oil equivalent
mcf			thousand cubic feet
mcf/d			thousand cubic feet per day
mmboe			million barrel of oil equivalent
mmcf			million cubic feet
mmcf/d			million cubic feet per day
MWh			megawatt hour
NGLs			natural gas liquids
NGTL			NOVA Gas Transmission Ltd., a wholly owned subsidiary of TransCanada is the owner of a gas transmission system known as the NGTL system. The NGTL system is a 23,500 km pipeline that gathers natural gas for both use in Alberta, and to deliver it to provincial border points for export to North American markets.
PRRT			Petroleum Resource Rent Tax, a profit based tax levied on petroleum projects in Australia
TTF			the day-ahead price for natural gas in the Netherlands, quoted in MWh of natural gas, at the Title Transfer Facility Virtual Trading Point operated by Dutch TSO Gas Transport Services
WTI			West Texas Intermediate, the reference price paid for crude oil of standard grade in US dollars at Cushing, Oklahoma

MESSAGE TO SHAREHOLDERS

Crude oil prices once again came under significant pressure during the third quarter of 2015 with WTI reaching its lowest level since the financial crisis of 2008-2009. This continued price volatility, coupled with an emerging consensus that we are in a "lower for longer" price environment, provides an opportunity to share our perspective on Vermilion's strengths in today's challenging conditions.

Sustainability
Since inception, we have remained highly disciplined in our approach to financial management. We have historically targeted our cash outflows (net cash dividends, capital expenditures plus abandonment and reclamation costs) at levels equal to, or less than, our cash inflows (fund flows from operations.) In addition, we have targeted moderate leverage ratios, enabling us to manage through lower commodity price environments and take advantage of compelling business opportunities. This conservative approach allowed us to enter the current commodity price downturn in a position of relative financial strength as compared to many of our peers and to avoid large equity issues during this part of the commodity cycle.

Sustainability has always been paramount in our dividend policy. We have raised the dividend three times since it was initiated in 2003. We have never reduced our dividend, and we do not foresee the need to do so in the future.

We have proactively managed our credit capacity to ensure sufficient liquidity to meet the expected requirements of our business, irrespective of the financial environment. Vermilion has a 4-year revolving credit facility totalling $2.0 billion and more than $700 million of borrowing capacity available at the end of the quarter. We are, and expect to continue to remain, in compliance with all applicable debt covenants. We currently intend to use our revolving credit facility to retire $225 million in senior unsecured notes that mature in February 2016 as we continue to evaluate options for long-term refinancing.

Vermilion's management approach allows us to quickly adapt to changes in the external environment. Following the unexpected commodity downturn in 2014, we acted decisively to reduce our 2015 capital program by 30% from 2014 levels. We are once again taking action to preserve our financial flexibility and maintain a sustainable business model by targeting a preliminary capital expenditure level for 2016 of approximately $350MM, a nearly 50% reduction from 2014 expenditures levels. In the latter part of 2014, we introduced the third installment of our Profitability Enhancement Program ("PEP") to identify opportunities to reduce costs to support the long-term profitability of our Company. Prior installments of PEP achieved strong results in both the 1998 industry downturn and the financial crisis of 2008-2009. We expect that our third installment of PEP will result in cost savings related to capital spending, operating expense and G&A expenditures estimated at between $70 and $80 million for full-year 2015.

Diversification
Vermilion's international diversification has played a significant role in our success, and is a key advantage differentiating us from our peer group. Over the past number of years, we have benefitted from the premium that our Brent-priced oil production has received as compared to WTI-based oil production in North America. More recently, our growing exposure to European natural gas has supported our ability to continue to deliver strong financial results in the current commodity price environment. As European natural gas prices remain at levels approximately three times those in North America, a significant part of our strategic focus has been on maximizing our exposure to this advantageously-priced commodity. In addition, our growing exposure to European natural gas also helps to reduce the volatility of our composite revenue stream. This, in turn, reduces the volatility of our internally-generated cash flow which funds our capital program and cash dividends.

Another key benefit of Vermilion's geographic diversity is that it provides the Company with a large inventory of potential capital investment opportunities. This allows us to select and fund projects that will generate the highest return in a given economic environment. This advantage is even more important in a low commodity price environment in which available capital funding is highly restricted.

Opportunity
Vermilion has a large resource base in its three operating regions which present a number of diverse, high-return, organic investment opportunities. We believe that this resource base leaves us well-positioned for long-term, value-adding, organic growth. In addition, our strong asset and operating positions result in significant advantages over our competitors in a number of jurisdictions, particularly in onshore Europe. This "franchise" has historically led to enhanced returns on acquisition opportunities as compared to what can typically be achieved in North America alone. We believe Vermilion remains positioned to deliver both continued organic growth and the potential for opportunistic, high return acquisitions, while maintaining sustainable and growing dividends to our shareholders.

Third Quarter Review
Record quarterly production of 56,280 boe/d for Q3 2015 exceeded prior quarter production of 51,831 boe/d by 9%. This quarter-over-quarter increase was primarily attributable to higher production in the Netherlands due to recent drilling success, with additional contributions from the Canadian Mannville drilling program and increased Australian oil production. Canadian third-party facility restrictions impacted average production by approximately 900 boe/d during Q3.

In July, we placed two Netherlands wells (Slootdorp-06/07 - 92.8% working interest) on production for an extended production test. The two wells, drilled in the prior quarter, contributed approximately 24 mmcf/d (4,000 boe/d) to the quarter's average production rate. We also executed various debottlenecking activities, both during and after the quarter, to enhance deliverability from these wells. The Diever-02 exploration well (45% working interest), drilled in 2014, came on production in early November for an extended production test at a gross rate of 28.5 mmcf/d (4,750 boe/d). Because of current pipeline constraints in the multi-well system that Diever-02 produces into, Vermilion's net incremental production increase from this well is limited to approximately 6 mmcf/d (1,000 boe/d), net to Vermilion.

In France, production from the four (4.0 net) well Champotran drilling program executed in Q1 2015 continues to exceed expectations. After converting one of the wells to a waterflood injector, total oil production from the remaining three producing wells was approximately 820 bbls/d at the end of the quarter. Results from other activities directed at our Champotran field have also been highly positive. Our Champotran waterflood program has continued to provide strong results, delivering highly capital efficient production growth. We recorded an increase of approximately 300 bbls/d over the course of Q3 due to new response from the waterflood, increasing total Champotran field production by approximately 10%.

With respect to the German farm-in agreement that we signed in July, all joint venture partners have now approved Vermilion as a new partner, allowing for the transfer of operatorship where applicable and access to the proprietary geologic data associated with the underlying assets. We continue to expect to close the farm-in toward the end of the year, once all government consents have been received. During Q3, the Burgmoor Z3a sidetrack well that was drilled in the second quarter (25% Vermilion working interest) was placed on production and is currently producing at a rate of approximately 1.7 mmcf/d (280 boe/d), net to Vermilion.

Our Australian horizontal sidetrack drill program commenced in early October after the arrival of the drilling rig at the Wandoo A platform in late September. Vermilion expects that the well will be completed and placed on production during the fourth quarter of 2015.

Vermilion is pleased to confirm that the Irish Environmental Protection Agency issued its final determination in support of the Corrib Industrial Emissions License on October 8, 2015. Previously, on September 1, 2015 the operator, Shell E&P Ireland Limited declared the project ready for service. As a result, the sole remaining requirement prior to commencing gas production at Corrib is the receipt of Ministerial Consent from Ireland's Department of Communications, Energy and Natural Resources. Following start-up, production levels at Corrib are expected to rise over a period of approximately six months to a peak rate estimated at 58 mmcf/d (9,700 boe/d), net to Vermilion by mid-2016. While the final regulatory approvals have taken longer than we originally expected, we believe that the regulatory process for Corrib is near completion, and still expect to achieve first production in approximately mid-Q4 2015. We believe that our ability to maintain our 2015 production guidance (originally set in March 2014) and achieve more than 10% annual production growth, despite the later-than-expected start-up of Corrib and 30% lower year-over-year capital expenditures, is indicative of the operational strength of our Company.

In the United States, we completed and began testing one (1 net) Turner Shurley Sand well in the eastern Powder River Basin of Wyoming. During the third quarter, we consolidated our ownership of this project area to 100% working interest through the acquisition of the remaining 30% interest that was previously outstanding. The purchase price of US $9.6 million provides Vermilion with an estimated 0.9 mmboe of 2P reserves plus substantial contingent resource opportunity, another 22,000 net acres of land, and a nominal amount of incremental production.

In Canada, we drilled five (4.5 net) operated, and participated in six (2.4 net) non-operated, Mannville wells during Q3 2015. A total of 10 (5.5 net) operated and non-operated Mannville wells were brought on production. Subsequent to the quarter, a recently completed two-mile Mannville well targeting the Notikewin formation flowed at a restricted rate of 10.7 mmcf/d (1,780 boe/d) on a production test with casing pressure of 4,700 psi⁽²⁾. Based on available processing and transportation capacity, we expect to put this well on production in Q4 at a rate of between 12 to 14 mmcf/d (2,000 to 2,300 boe/d). This level of productivity would rank this well amongst the top gas wells currently producing in Alberta. Although access to natural gas processing and takeaway capacity is modestly improving in Alberta, we continue to be negatively impacted by third party plant capacity restrictions, with approximately 900 boe/d of primarily non-operated production offline throughout Q3. In addition, we expect that approximately 2,400 boe/d of productive capacity will be equipped and tied-in during Q4, but will remain shut-in until processing capacity becomes available.

Subsequent to the quarter, Vermilion was named to the CDP Climate Disclosure Leadership Index ("CDLI"), recognizing the depth and quality of our climate-related disclosure as compared to the 200 largest companies listed on the TSX. CDP (formerly Carbon Disclosure Project), is a global, not-for-profit organization that manages the world's only global environmental disclosure system. To be named to the CDLI, a company must have a disclosure score within the top 10% of surveyed companies. Vermilion has voluntarily reported to CDP since 2012. We believe that by measuring and understanding our current environmental profile, we can direct our business strategy to operate in an even more environmentally and socially sustainable manner in the future.

The management and directors of Vermilion continue to hold approximately 6% of the outstanding shares and remain committed to delivering superior rewards to all stakeholders. In spite of the challenges posed by the current business environment, we continue to believe that Vermilion is situated for long-term, diversified growth. We remain confident that the assets in our portfolio can support long-term organic growth, and in the current environment, we also find ourselves well-positioned to take advantage of potential acquisition activity in North American and international markets. Our focus on the creation of real value through our technical capabilities, combined with our conservative financial approach and patience, should allow us to compete and transact for the benefit of our existing shareholders if suitable opportunities arise.

⁽¹⁾	The above discussion includes additional GAAP and non-GAAP measures which may not be comparable to other companies. Please see the "ADDITIONAL AND NON-GAAP FINANCIAL MEASURES" section of Management's Discussion and Analysis.
⁽²⁾	Production test was performed over a 6-day test period at a maximum choke of 21"/64" with approximately 5% drawdown over the test period. This test result is not necessarily indicative of long-term performance or of ultimate recovery.

MANAGEMENT'S DISCUSSION AND ANALYSIS

The following is Management's Discussion and Analysis ("MD&A"), dated November 5, 2015, of Vermilion Energy Inc.'s ("Vermilion", "We", "Our", "Us" or the "Company") operating and financial results as at and for the three and nine months ended September 30, 2015 compared with the corresponding periods in the prior year.

This discussion should be read in conjunction with the unaudited condensed consolidated interim financial statements for the three and nine months ended September 30, 2015 and the audited consolidated financial statements for the year ended December 31, 2014 and 2013, together with accompanying notes. Additional information relating to Vermilion, including its Annual Information Form, is available on SEDAR at www.sedar.com or on Vermilion's website at www.vermilionenergy.com.

The unaudited condensed consolidated interim financial statements for the three and nine months ended September 30, 2015 and comparative information have been prepared in Canadian dollars, except where another currency is indicated, and in accordance with IAS 34, "Interim Financial Reporting", as issued by the International Accounting Standard Board ("IASB").

This MD&A includes references to certain financial measures which do not have standardized meanings prescribed by International Financial Reporting Standards ("IFRS"). As such, these financial measures are considered additional GAAP or non-GAAP financial measures and therefore are unlikely to be comparable with similar financial measures presented by other issuers. These additional GAAP and non-GAAP financial measures include:

Fund flows from operations: This additional GAAP financial measure is calculated as cash flows from operating activities before changes in non-cash operating working capital and asset retirement obligations settled. We analyze fund flows from operations both on a consolidated basis and on a business unit basis in order to assess the contribution of each business unit to our ability to generate cash necessary to pay dividends, repay debt, fund asset retirement obligations and make capital investments.
Netbacks: These non-GAAP financial measures are per boe and per mcf measures used in the analysis of operational activities. We assess netbacks both on a consolidated basis and on a business unit basis in order to compare and assess the operational and financial performance of each business unit versus other business units and third party crude oil and natural gas producers.

For a full description of these and other non-GAAP financial measures and a reconciliation of these measures to their most directly comparable GAAP measures, please refer to "ADDITIONAL AND NON-GAAP FINANCIAL MEASURES".

VERMILION'S BUSINESS

Vermilion is a Calgary, Alberta based international oil and gas producer focused on the acquisition, development and optimization of producing properties in North America, Europe, and Australia. We manage our business through our Calgary head office and our international business unit offices.

This MD&A separately discusses each of our business units in addition to our corporate segment.

Canada business unit: Relates to our assets in Alberta and Saskatchewan.
France business unit: Relates to our operations in France in the Paris and Aquitaine Basins.
Netherlands business unit: Relates to our operations in the Netherlands.
Germany business unit: Relates to our operations in Germany.
Ireland business unit: Relates to our 18.5% non-operated interest in the Corrib offshore natural gas field.
Australia business unit: Relates to our operations in the Wandoo offshore crude oil field.
United States business unit: Relates to our operations in Wyoming in the Powder River Basin.
Corporate: Includes expenditures related to our global hedging program, financing expenses, and general and administration expenses, primarily incurred in Canada and not directly related to the operations of a specific business unit.

GUIDANCE

We first issued 2015 capital expenditure guidance of $525 million on December 8, 2014. We subsequently adjusted our 2015 capital expenditure guidance to $415 million on February 27, 2015, in response to the continued weakness in commodity prices. That reduction reflected lower planned activity levels, including the deferral of our Australian drilling program. On August 10, 2015 we announced an increase in our capital expenditure guidance of $70 million to $485 million following the reinstatement of the Australian drilling program as well as additional funding for projects in Canada, France and Ireland. We are maintaining our previous production guidance of 55,000-57,000 boe/d, albeit towards the lower end of our guidance range due to later-than-originally expected first gas from Corrib. On November 9, 2015 we announced preliminary 2016 capital expenditure guidance of $350 million and affirmed production guidance of between 63,000-65,000 boe/d.

The following table summarizes our 2015 and 2016 guidance:

Date

Capital Expenditures ($MM)

Production (boe/d)

2015 - Guidance

2015 Guidance

December 8, 2014

525

55,000 to 57,000

2015 Guidance

February 27, 2015

415

55,000 to 57,000

2015 Guidance

August 10, 2015

485

55,000 to 57,000

2016 - Guidance

2016 Guidance

November 9, 2015

350

63,000 to 65,000

SHAREHOLDER RETURN

Vermilion strives to provide investors with reliable and growing dividends in addition to sustainable, global production growth. The following table, as of September 30, 2015, reflects our trailing one, three, and five year performance:

Total return⁽¹⁾	Trailing One Year	Trailing Three Year	Trailing Five Year
Dividends per Vermilion share	$2.58	$7.49	$12.05
Capital appreciation per Vermilion share	-$25.21	-$3.23	$4.35
Total return per Vermilion share	-33.2%	9.2%	42.5%
Annualized total return per Vermilion share	-33.2%	3.0%	7.3%
Annualized total return on the S&P TSX High Income Energy Index	-42.4%	-12.5%	-5.7%

⁽¹⁾	The above table includes non-GAAP financial measures which may not be comparable to other companies. Please see the "ADDITIONAL AND NON-GAAP FINANCIAL MEASURES" section of this MD&A.

CONSOLIDATED RESULTS OVERVIEW

		Three Months Ended			% change		Nine Months Ended		% change
		Sep 30,	Jun 30,	Sep 30,	Q3/15 vs.	Q3/15 vs.	Sep 30,	Sep 30,	2015 vs.
		2015	2015	2014	Q2/15	Q3/14	2015	2014	2014
Production
	Crude oil (bbls/d)	28,164	28,916	29,147	(3%)	(3%)	28,420	28,890	(2%)
	NGLs (bbls/d)	4,622	3,867	2,354	20%	96%	3,849	2,463	56%
	Natural gas (mmcf/d)	140.97	114.29	110.52	23%	28%	123.51	109.33	13%
	Total (boe/d)	56,280	51,831	49,920	9%	13%	52,854	49,574	7%
	Build (draw) in inventory (mbbl)	(85)	(121)	104			177	74
Financial metrics
	Fund flows from operations ($M)	129,435	129,496	197,898	-	(35%)	379,726	619,337	(39%)
	Per share ($/basic share)	1.17	1.18	1.85	(1%)	(37%)	3.48	5.90	(41%)
	Net earnings (loss)	(83,310)	6,813	53,903	(1,323%)	(255%)	(75,222)	210,684	(136%)
	Per share ($/basic share)	(0.76)	0.06	0.50	(1,367%)	(252%)	(0.69)	2.01	(134%)
	Cash flows from operating activities ($M)	122,230	134,668	235,010	(9%)	(48%)	279,545	562,840	(50%)
	Net debt ($M)	1,363,043	1,377,902	1,243,438	(1%)	10%	1,363,043	1,243,438	10%
	Cash dividends ($/share)	0.645	0.645	0.645	-	-	1.935	1.935	-
Activity
	Capital expenditures ($M)	93,381	90,173	190,033	4%	(51%)	357,865	521,481	(31%)
	Acquisitions ($M)	22,155	480	40,847	4,516%	(46%)	22,670	600,213	(96%)
	Gross wells drilled	11.00	5.00	26.00			45.00	63.00
	Net wells drilled	6.91	3.61	20.31			30.56	45.86

Operational review

Recorded consolidated average production of 56,280 boe/d during Q3 2015, which was a 9% increase over Q2 2015 as a result of production growth in the Netherlands, Australia, and Canada, driven primarily by new wells on production.
Increased consolidated average production for the three and nine months ended September 30, 2015 by 13% and 7%, respectively, versus the comparable periods in 2014, primarily due to growth in the Netherlands, Canada, and France.
Activity during the quarter included capital expenditures totalling $93.4 million, incurred primarily in Canada, Ireland, and France. In Canada, capital expenditures totalling $37.2 million were 70% higher than the $21.9 million incurred in Q2 2015 and related to the drilling of 6.91 net wells (0.5 net wells in Q2 2015), with activity influenced by spring breakup in Q2 2015. In Ireland, capital expenditures of $20.7 million were incurred, the majority of which related to subsurface activities and facility commissioning. In France, capital expenditures of $17.4 million were consistent with the $16.7 million incurred in Q2 2015 and related to accretive workovers and subsurface activity.

Financial review

Net earnings (loss)

The net loss for Q3 2015 was $83.3 million ($0.76/basic share) as compared to net earnings of $6.8 million ($0.06/basic share) in Q2 2015. The decrease in net earnings (loss) was primarily attributable to a non-cash impairment charge ($104.0 million after-tax) recognized in Q3 2015 following a steep decline in forward commodity prices. In addition, the change in net earnings (loss) for Q3 2015 saw lower petroleum and natural gas sales driven by lower commodity prices, partially offset by higher sold volumes, impacts from unrealized gains on derivative instruments and foreign exchange, and lower current income taxes.
The net loss incurred for the three and nine months ended September 30, 2015 represented decreases of $137.2 million and $285.9 million, respectively, versus the comparative periods in 2014. These decreases were driven primarily by the aforementioned impairment charge recognized in the current period and lower petroleum and natural gas sales as a result of lower commodity prices. These declines were partially offset by decreases in royalties and taxes, as well as gains on derivative instruments and the impact of unrealized foreign exchange gains. In the nine months ended September 30, 2015, the decrease in net earnings was partially offset by the recovery of $31.8 million (before taxes) recognized in Q1 2015 following a judgment in favor of Vermilion for costs incurred as a result of a 2007 oil spill at the Ambès oil terminal in France that occurred shortly after Vermilion acquired the asset.

Cash flows from operating activities

Cash flows from operating activities decreased by 48% and 50% for the three and nine months ended September 30, 2015, respectively, versus the comparable periods in 2014. These decreases primarily relate to lower revenue due to lower commodity prices and timing differences pertaining to working capital, partially offset by foreign exchange gains and lower current taxes.
Absent changes in working capital, cash flows from operating activities was consistent quarter-over-quarter.

Fund flows from operations

Generated fund flows from operations of $129.4 million during Q3 2015, consistent with fund flows from operations generated in Q2 2015. Fund flows from operations were impacted by lower sales, driven by lower realized prices but partially offset by higher volumes sold, a realized gain on derivative instruments, and a favorable current tax variance.
Fund flows from operations decreased 35% and 39% for the three and nine months ended September 30, 2015, respectively, versus the comparable periods in 2014. These decreases were primarily driven by lower crude oil pricing, partially offset by higher sold volumes as well as favorable royalty and current tax variances, consistent with lower commodity prices. The decrease in fund flows from operations for the nine months ended September 30, 2015 was partially offset by the previously mentioned recovery of costs in France.

Net debt

Net debt increased by $97.4 million to $1.36 billion for the nine months ended September 30, 2015 due to capital expenditures in Canada, Ireland and Australia, partially offset by fund flows from operations which were comparatively lower due to weaker commodity prices in 2015.

Dividends

Declared dividends remained consistent at $0.215 per common share per month during the third quarter of 2015, totalling $0.645 per common share and $1.935 per common share for the three and nine months ended September 30, 2015, respectively.

COMMODITY PRICES

	Three Months Ended			% change		Nine Months Ended		% change
	Sep 30,	Jun 30,	Sep 30,	Q3/15 vs.	Q3/15 vs.	Sep 30,	Sep 30,	2015 vs.
	2015	2015	2014	Q2/15	Q3/14	2015	2014	2014
Average reference prices
WTI (US $/bbl)	46.43	57.94	97.17	(20%)	(52%)	51.00	99.61	(49%)
Edmonton Sweet index (US $/bbl)	43.01	55.08	89.24	(22%)	(52%)	46.64	92.17	(49%)
Dated Brent (US $/bbl)	50.26	61.92	101.85	(19%)	(51%)	55.39	106.57	(48%)
AECO ($/GJ)	2.75	2.52	3.81	9%	(28%)	2.62	4.56	(43%)
TTF ($/GJ)	8.04	7.94	7.26	1%	11%	8.08	8.41	(4%)
TTF (€/GJ)	5.52	5.84	5.04	(5%)	10%	5.76	5.68	1%
Average foreign currency exchange rates
CDN $/US $	1.31	1.23	1.09	7%	20%	1.26	1.09	15%
CDN $/Euro	1.46	1.36	1.44	7%	1%	1.40	1.48	(5%)
Average realized prices ($/boe)
Canada	32.78	40.59	64.85	(19%)	(49%)	36.34	68.58	(47%)
France	60.96	71.96	107.99	(15%)	(44%)	65.66	114.36	(43%)
Netherlands	49.42	47.63	45.73	4%	8%	48.70	52.80	(8%)
Germany	44.36	43.31	36.43	2%	22%	44.30	44.68	(1%)
Australia	68.20	80.87	119.07	(16%)	(43%)	76.46	124.59	(39%)
United States	51.60	60.57	-	(15%)	100%	52.95	-	100%
Consolidated	46.56	54.65	76.80	(15%)	(39%)	49.48	82.73	(40%)
Production mix (% of production)
% priced with reference to WTI	24%	27%	28%			26%	27%
% priced with reference to AECO	22%	21%	18%			21%	18%
% priced with reference to TTF	20%	16%	18%			18%	18%
% priced with reference to Dated Brent	34%	36%	36%			35%	37%

Reference prices

Despite higher demand, crude oil markets moved lower over the three months ended September 30, 2015 as global production edged higher. As compared to Q2 2015, WTI fell by 20% to average US $46.43/bbl while Dated Brent was down 19% to average US $50.26/bbl.
Crude oil prices set at Edmonton were volatile in Q3 2015 due to fluctuations in supply and refining demand, with the reference price declining by 22% over the prior quarter to average US $43.01/bbl.
Pipeline constraints and a relatively warm summer proved to be supportive factors for AECO natural gas, with prices increasing 9% quarter-over-quarter to average $2.75/GJ.
European natural gas held firm in Canadian dollar terms quarter-over-quarter, averaging $8.04/GJ for the three months ended September 30, 2015, up 1% over the previous quarter, while TTF natural gas pricing, based on Euro per gigajoule, was down 5% quarter-over-quarter.
The US dollar continued to strengthen against the Canadian dollar during Q3 2015 driven by the combination of weakening crude oil prices and larger interest rate spreads. For the three months ended September 30, 2015, 1 US dollar bought 1.31 Canadian dollars, which is 7% more than the previous quarter and 20% more than the same period in 2014.

Realized prices

Consolidated realized price decreased by 15% for Q3 2015 as compared to Q2 2015. This decrease was the result of weakening crude oil pricing, partially offset by a slight improvement in North American natural gas pricing.
Consolidated realized price for the three and nine months ended September 30, 2015 decreased by 39% and 40%, respectively, as compared to the comparable periods in 2014. These decreases were driven by a weakening of crude oil and North American natural gas pricing, as well as changes in production mix, which included increased relative NGL and natural gas volume on the production mix in Canada.

FUND FLOWS FROM OPERATIONS

	Three Months Ended						Nine Months Ended
	Sep 30, 2015		Jun 30, 2015		Sep 30, 2014		Sep 30, 2015		Sep 30, 2014
	$M	$/boe	$M	$/boe	$M	$/boe	$M	$/boe	$M	$/boe
Petroleum and natural gas sales	245,051	46.56	264,331	54.65	344,688	76.80	705,267	49.48	1,113,555	82.73
Royalties	(17,100)	(3.25)	(16,111)	(3.33)	(29,000)	(6.46)	(49,635)	(3.48)	(82,037)	(6.09)
Petroleum and natural gas revenues	227,951	43.31	248,220	51.32	315,688	70.34	655,632	46.00	1,031,518	76.64
Transportation expense	(11,090)	(2.11)	(10,883)	(2.25)	(10,979)	(2.45)	(31,513)	(2.21)	(32,872)	(2.44)
Operating expense	(57,826)	(10.99)	(58,616)	(12.12)	(56,227)	(12.53)	(160,293)	(11.25)	(172,426)	(12.81)
General and administration	(13,088)	(2.49)	(14,505)	(3.00)	(16,262)	(3.62)	(41,153)	(2.89)	(48,491)	(3.60)
PRRT	(99)	(0.02)	(3,371)	(0.70)	(13,834)	(3.08)	(5,824)	(0.41)	(46,772)	(3.47)
Corporate income taxes	(12,383)	(2.35)	(17,344)	(3.59)	(17,454)	(3.89)	(47,350)	(3.32)	(88,692)	(6.59)
Interest expense	(15,420)	(2.93)	(14,550)	(3.01)	(12,918)	(2.88)	(43,268)	(3.04)	(36,712)	(2.73)
Realized gain on derivative instruments	10,854	2.06	3,081	0.64	8,837	1.97	20,192	1.42	13,896	1.03
Realized foreign exchange gain (loss)	309	0.06	(2,740)	(0.57)	812	0.17	875	0.06	(642)	(0.05)
Realized other income	227	0.04	204	0.04	235	0.05	32,428	2.28	530	0.04
Fund flows from operations	129,435	24.58	129,496	26.76	197,898	44.08	379,726	26.64	619,337	46.02

The following table shows a reconciliation of the change in fund flows from operations:

($M)		Q3/15 vs. Q2/15	Q3/15 vs. Q3/14	2015 vs. 2014
Fund flows from operations - Comparative period		129,496	197,898	619,337
Sales volume variance:
	Canada	1,563	5,575	21,485
	France	8,590	27,004	27,133
	Netherlands	15,660	11,159	1,418
	Germany	(1,322)	(768)	3,240
	Australia	(9,574)	4,948	(25,421)
	United States	585	1,075	2,424
Pricing variance on sold volumes:
	WTI	(16,203)	(56,611)	(165,078)
	AECO	662	(10,324)	(35,040)
	Dated Brent	(20,970)	(86,359)	(230,151)
	TTF	1,729	4,664	(8,298)
Changes in:
	Royalties	(989)	11,900	32,402
	Transportation	(207)	(111)	1,359
	Operating expense	790	(1,599)	12,133
	General and administration	1,417	3,174	7,338
	PRRT	3,272	13,735	40,948
	Corporate income taxes	4,961	5,071	41,342
	Interest	(870)	(2,502)	(6,556)
	Realized derivatives	7,773	2,017	6,296
	Realized foreign exchange	3,049	(503)	1,517
	Realized other income	23	(8)	31,898
Fund flows from operations - Current period		129,435	129,435	379,726

Fund flows from operations of $129.4 million during Q3 2015 was consistent with fund flows from operations generated in Q2 2015. Fund flows from operations was impacted by weaker crude oil pricing, offset by higher sales volumes and favorable current tax variances. Sales decreased by $19.3 million, which included a $34.8 million unfavorable pricing variance driven by weaker crude oil prices partially offset by a $15.5 million sales volumes variance driven by increased sales in the Netherlands and France. In France, the increase in sold volumes resulted from a draw in inventory of 101,000 bbls (as compared to a build of 41,000 bbls in Q2 2015). This decrease in sales was offset by lower PRRT and corporate income taxes, as well as realized gains on both derivatives and foreign exchange.

Fund flows from operations decreased by 35% and 39% for the three and nine months ended September 30, 2015, respectively, versus the comparable periods in the prior year. These decreases were primarily driven by unfavorable crude oil and natural gas pricing variances, partially offset by favorable royalty and current income tax variances. For the three months ended September 30, 2015, the decrease in fund flows from operations was further offset by a favorable sales volume variance of $49.0 million including an increase in sold volumes in France of $27.0 million. For the nine months ended September 30, 2015, the decrease in fund flows from operations was partially offset by a $30.3 million favorable sales volume variance driven by France and Canada, as well as the recognition of the $31.8 million (before taxes) recovery in France recognized in Q1 2015.

Fluctuations in fund flows from operations (and correspondingly net earnings and cash flows from operating activities) may occur as a result of changes in commodity prices and costs to produce petroleum and natural gas. In addition, fund flows from operations may be highly affected by the timing of crude oil shipments in Australia and France. When crude oil inventory is built up, the related operating expense, royalties, and depletion expense are deferred and carried as inventory on the balance sheet. When the crude oil inventory is subsequently drawn down, the related expenses are recognized in fund flows from operations.

CANADA BUSINESS UNIT

Overview

Production and assets focused in West Pembina near Drayton Valley, Alberta and Northgate in southeast Saskatchewan.
Potential for three significant resource plays sharing the same surface infrastructure in the West Pembina region:

Cardium light oil (1,800m depth) - in development phase
Mannville condensate-rich gas (2,400 - 2,700m depth) - in development phase
Duvernay condensate-rich gas (3,200 - 3,400m depth) - in appraisal phase

Canadian cash flows are fully tax-sheltered for the foreseeable future.

Operational review

		Three Months Ended			% change		Nine Months Ended		% change
		Sep 30,	Jun 30,	Sep 30,	Q3/15 vs.	Q3/15 vs.	Sep 30,	Sep 30,	2015 vs.
Canada business unit		2015	2015	2014	Q2/15	Q3/14	2015	2014	2014
Production
	Crude oil (bbls/d)	9,195	10,182	11,469	(10%)	(20%)	10,083	11,202	(10%)
	NGLs (bbls/d)	4,513	3,755	2,291	20%	97%	3,754	2,387	57%
	Natural gas (mmcf/d)	71.94	64.66	57.07	11%	26%	66.16	54.76	21%
	Total (boe/d)	25,698	24,713	23,272	4%	10%	24,864	22,714	9%
Production mix (% of total)
	Crude oil	36%	41%	49%			41%	49%
	NGLs	18%	15%	10%			15%	11%
	Natural gas	46%	44%	41%			44%	40%
Activity
	Capital expenditures ($M)	37,224	21,881	97,393	70%	(62%)	173,954	249,300	(30%)
	Acquisitions ($M)	8,062	384	27,883			8,481	413,977
	Gross wells drilled	11.00	1.00	22.00			37.00	51.00
	Net wells drilled	6.91	0.50	16.86			23.45	35.12

Production

Average production in Canada increased by 4% quarter-over-quarter, 10% year-over-year and 9% year-to-date, primarily due to strong organic production growth in our Mannville condensate-rich gas resource play. Q3 2015 volumes were negatively impacted by approximately 900 boe/d of production offline as a result of third-party plant capacity restrictions. Approximately 2,400 boe/d is awaiting equip and tie in, which is anticipated to be completed in Q4 2015, but this production is expected to remain shut-in due to third party processing constraints.
Cardium production averaged approximately 9,300 boe/d in Q3 2015, essentially flat quarter-over-quarter.
Mannville production averaged more than 7,000 boe/d in Q3 2015, a 25% increase quarter-over-quarter.
Production from our southeast Saskatchewan assets averaged approximately 3,000 boe/d in Q3 2015, a decrease of 9% quarter-over-quarter. The North Portal Gas Plant was commissioned late in Q1 2015. The plant enables the processing of approximately 5,500 mcf/d (920 boe/d) net of natural gas which was previously being flared.

Activity review

Vermilion drilled five (4.5 net) operated wells and participated in the drilling of six (2.4 net) non-operated wells during Q3 2015.

Cardium

During Q3 2015, no new wells were drilled or brought on production.
Year-to-date, we have drilled or participated in seven (3.1 net) wells and 18 (11.9 net) wells were placed on production. For the remainder of the year, we plan to participate in the drilling of two (0.3 net) non-operated wells.

Mannville

During Q3 2015, we drilled five (4.5 net) operated wells and brought four (3.0 net) operated wells on production. We also participated in the drilling of six (2.4 net) non-operated wells and six (2.5 net) non-operated wells were placed on production.
Year-to-date, we have drilled or participated in 25 (16.3 net) wells and 19 (12.0 net) wells were placed on production. For the remainder of the year, we plan to drill two (0.6 net) operated wells, and place two (2.0 net) operated and three (1.3 net) non-operated wells on production.

Saskatchewan

We drilled and brought on production five (4.1 net) operated Midale wells during Q1 2015, completing our 2015 drilling activity in Saskatchewan.

Financial review

		Three Months Ended			% change		Nine Months Ended		% change
Canada business unit		Sep 30,	Jun 30,	Sep 30,	Q3/15 vs.	Q3/15 vs.	Sep 30,	Sep 30,	2015 vs.
($M except as indicated)		2015	2015	2014	Q2/15	Q3/14	2015	2014	2014
	Sales	77,493	91,284	138,853	(15%)	(44%)	246,661	425,294	(42%)
	Royalties	(6,638)	(5,768)	(19,034)	15%	(65%)	(20,998)	(49,937)	(58%)
	Transportation expense	(4,131)	(4,469)	(4,048)	(8%)	2%	(12,542)	(11,170)	12%
	Operating expense	(23,877)	(21,534)	(19,074)	11%	25%	(64,510)	(56,863)	13%
	General and administration	(3,694)	(5,510)	(4,523)	(33%)	(18%)	(13,219)	(13,951)	(5%)
	Fund flows from operations	39,153	54,003	92,174	(27%)	(58%)	135,392	293,373	(54%)
Netbacks ($/boe)
	Sales	32.78	40.59	64.85	(19%)	(49%)	36.34	68.58	(47%)
	Royalties	(2.81)	(2.56)	(8.89)	10%	(68%)	(3.09)	(8.05)	(62%)
	Transportation expense	(1.75)	(1.99)	(1.89)	(12%)	(7%)	(1.85)	(1.80)	3%
	Operating expense	(10.10)	(9.58)	(8.91)	5%	13%	(9.50)	(9.17)	4%
	General and administration	(1.56)	(2.45)	(2.11)	(36%)	(26%)	(1.95)	(2.25)	(13%)
	Fund flows from operations netback	16.56	24.01	43.05	(31%)	(62%)	19.95	47.31	(58%)
Reference prices
	WTI (US $/bbl)	46.43	57.94	97.17	(20%)	(52%)	51.00	99.61	(49%)
	Edmonton Sweet index (US $/bbl)	43.01	55.08	89.24	(22%)	(52%)	46.64	92.17	(49%)
	Edmonton Sweet index ($/bbl)	56.32	67.72	97.21	(17%)	(42%)	58.77	100.87	(42%)
	AECO ($/GJ)	2.75	2.52	3.81	9%	(28%)	2.62	4.56	(43%)

Sales

The realized price for our crude oil production in Canada is directly linked to WTI, but is also subject to market conditions in Western Canada. These market conditions can result in fluctuations in the pricing differential to WTI, as reflected by the Edmonton Sweet index price. The realized price of our NGLs in Canada is based on product specific differentials pertaining to trading hubs in the United States. The realized price of our natural gas in Canada is based on the AECO spot price in Canada.
Sales per boe decreased by 19% quarter-over-quarter as a result of a 17% decrease in Edmonton Sweet index pricing in Canadian dollar terms offset by a 9% increase in AECO pricing. The pricing decrease for crude oil production, coupled with the increased relative NGL and natural gas volume on the production mix, more than offset a 4% increase in Canadian production volumes, resulting in a 15% decrease in sales.
On a year-over-year basis, sales per boe decreased by 49% and 47% for the three and nine months ended September 30, 2015, largely as the result of weakening crude oil and natural gas pricing. In both periods, the lower pricing was slightly offset by an increase in production volumes of approximately 10%, resulting in a decrease in sales of 44% and 42% for the three and nine months ended September 30, 2015, respectively.

Royalties

Royalties as a percentage of sales for Q3 2015 increased to 8.6% as compared to Q2 2015 of 6.3% despite lower reference prices (which would typically result in lower royalty rates) due to the timing of when par prices used in the royalty calculations were set. This timing difference resulted in lower crude oil royalty rates for Q2 2015 and higher crude oil royalty rates for Q3 2015. In addition, an annual favorable gas cost allowance ("GCA") adjustment in Alberta resulted in gas royalties being in a recovery position for the second quarter.
Royalties as a percentage of sales for the three and nine months ended September 30, 2015 decreased to 8.6% and 8.5% versus 13.7% and 11.7% for the same periods in 2014 due to the impact of lower reference prices on the sliding scale used to determine crude oil royalty rates.

Transportation

Transportation expense relates to the delivery of crude oil and natural gas production to major pipelines where legal title transfers.
Transportation expense for Q3 2015 was lower than Q2 2015 as a result of lower transportation rates for our Alberta natural gas liquids production.
Transportation expense for the nine months ended September 30, 2015 was higher than the same period in the prior year as a result of incremental trucking costs from Vermilion's Saskatchewan properties, which were acquired in April 2014.

Operating expense

Operating expenses were higher on a dollar and per boe basis for Q3 2015 versus both Q2 2015 and Q3 2014 as a result of higher gas processing fees attributable to increased production being processed at third party facilities.
Year-over-year operating expense increased on a dollar basis by approximately 13% due to incremental operating expense associated with Vermilion's Saskatchewan properties acquired in Q2 2014 and the aforementioned higher gas processing fees. This dollar increase was partially offset by increased production, resulting in a 4% increase in operating expense per boe.

General and administration

General and administration expense decreased for Q3 2015 versus both Q2 2015 and Q3 2014 as a result of timing of expenditures.
Year-over-year, general and administration expense for the nine months ended September 30, 2015 were 5% lower than 2014 due to a focus on cost reduction initiatives.

Impairment

For the three months ended September 30, 2015, Vermilion recorded an impairment charge of $143.0 million related to the light crude oil play in Saskatchewan, Canada. These impairment charges were a result of declines in the price forecasts for crude oil in Canada which decreased the expected future cash flows from the cash generating unit ("CGU").

FRANCE BUSINESS UNIT

Overview

Entered France in 1997 and completed three subsequent acquisitions, including two in 2012.
Largest oil producer in France, constituting approximately three-quarters of domestic oil production.
Producing assets include large conventional fields with high working interests located in the Aquitaine and Paris Basins with an identified inventory of workover, infill drilling, and secondary recovery opportunities.
Production is characterized by Brent-based crude pricing and low base decline rates.

Operational review

		Three Months Ended			% change		Nine Months Ended		% change
		Sep 30,	Jun 30,	Sep 30,	Q3/15 vs.	Q3/15 vs.	Sep 30,	Sep 30,	2015 vs.
France business unit		2015	2015	2014	Q2/15	Q3/14	2015	2014	2014
Production
	Crude oil (bbls/d)	12,310	12,746	11,111	(3%)	11%	12,176	10,970	11%
	Natural gas (mmcf/d)	1.47	1.03	-	43%	100%	0.84	-	100%
	Total (boe/d)	12,555	12,917	11,111	(3%)	13%	12,316	10,970	12%
Inventory (mbbls)
	Opening crude oil inventory	340	299	179			197	268
	Crude oil production	1,133	1,160	1,022			3,324	2,995
	Crude oil sales	(1,234)	(1,119)	(987)			(3,282)	(3,049)
	Closing crude oil inventory	239	340	214			239	214
Production mix (% of total)
	Crude oil	98%	99%	100%			99%	100%
	Natural gas	2%	1%	-			1%	-
Activity
	Capital expenditures ($M)	17,369	16,697	35,082	4%	(50%)	68,180	110,663	(38%)
	Acquisitions ($M)	142	96	-			238	-
	Gross wells drilled	-	-	3.00			4.00	7.00
	Net wells drilled	-	-	3.00			4.00	7.00

Production

Ongoing workover and optimization activities resulted in stable quarter-over-quarter production. Production increased for the current quarter and year-to-date periods as compared to the same periods in the prior year due to production additions from our 2015 Champotran drilling program and workovers.

Activity review

Vermilion drilled four (4.0 net) wells in the Champotran field in the Paris Basin in Q1 2015, completing our planned France drilling program for 2015.
In 2015, additional activity includes a 26-well workover program and the resumption of sales from a portion of our shut-in natural gas at Vic Bilh, which was brought on-line in Q2 2015.

Financial review

		Three Months Ended			% change		Nine Months Ended		% change
France business unit		Sep 30,	Jun 30,	Sep 30,	Q3/15 vs.	Q3/15 vs.	Sep 30,	Sep 30,	2015 vs.
($M except as indicated)		2015	2015	2014	Q2/15	Q3/14	2015	2014	2014
	Sales	76,552	81,627	106,576	(6%)	(28%)	218,011	348,753	(37%)
	Royalties	(8,038)	(6,620)	(6,978)	21%	15%	(19,760)	(22,125)	(11%)
	Transportation expense	(4,566)	(3,526)	(4,741)	29%	(4%)	(11,103)	(14,879)	(25%)
	Operating expense	(11,998)	(12,102)	(15,215)	(1%)	(21%)	(34,926)	(48,185)	(28%)
	General and administration	(5,338)	(4,874)	(6,411)	10%	(17%)	(15,323)	(17,164)	(11%)
	Other income	-	-	-	-	-	31,775	-	100%
	Current income taxes	(4,696)	(9,316)	(10,744)	(50%)	(56%)	(28,293)	(60,769)	(53%)
	Fund flows from operations	41,916	45,189	62,487	(7%)	(33%)	140,381	185,631	(24%)
Netbacks ($/boe)
	Sales	60.96	71.96	107.99	(15%)	(44%)	65.66	114.36	(43%)
	Royalties	(6.40)	(5.84)	(7.07)	10%	(9%)	(5.95)	(7.26)	(18%)
	Transportation expense	(3.64)	(3.11)	(4.80)	17%	(24%)	(3.34)	(4.88)	(32%)
	Operating expense	(9.55)	(10.67)	(15.42)	(10%)	(38%)	(10.52)	(15.80)	(33%)
	General and administration	(4.25)	(4.30)	(6.50)	(1%)	(35%)	(4.61)	(5.63)	(18%)
	Other income	-	-	-	-	-	9.57	-	100%
	Current income taxes	(3.74)	(8.21)	(10.89)	(54%)	(66%)	(8.52)	(19.93)	(57%)
	Fund flows from operations netback	33.38	39.83	63.31	(16%)	(47%)	42.29	60.86	(31%)
Reference prices
	Dated Brent (US $/bbl)	50.26	61.92	101.85	(19%)	(51%)	55.39	106.57	(48%)
	Dated Brent ($/bbl)	65.81	76.12	110.95	(14%)	(41%)	69.79	116.63	(40%)

Sales

Crude oil in France is priced with reference to Dated Brent.
Sales per boe decreased by 15% quarter-over-quarter, consistent with a 14% decrease in the Canadian dollar equivalent of the Dated Brent reference price. This decrease was partially offset by a 101,000 bbls draw in inventory during the quarter, resulting in a 6% decrease in sales.
On a year-over-year basis, sales decreased by 28% and 37% for the three and nine months ended September 30, 2015, respectively. In both periods, this was consistent with a decrease in the Dated Brent reference price, and was partially offset by increases in sold volumes, largely driven by increases in production.

Royalties

Royalties in France relate to two components: RCDM (levied on units of production and not subject to changes in commodity prices) and R31 (based on a percentage of revenue).
Royalties as a percentage of sales was 10.5% for Q3 2015 versus 8.1% for Q2 2015 due to the impact of fixed RCDM royalties coupled with lower realized pricing.
Royalties as a percentage of sales was 10.5% and 9.1% for the three and nine months ended September 30, 2015, an increase over both comparable periods in 2014 as a result of the impact of fixed RCDM royalties coupled with lower realized pricing.

Transportation

Transportation expense increased for Q3 2015 as compared to Q2 2015 due to a higher number of shipments from the Ambès terminal during the current quarter.
Transportation expense decreased for both the three and nine months ended September 30, 2015 as compared to the same periods in 2014 due to a lower level of maintenance and project activity at the Ambès terminal coupled with cost savings associated with fewer shipments at the terminal due to the usage of larger shipping vessels.

Operating expense

On a dollar and per boe basis, Q3 2015 operating expense was lower than Q2 2015 despite unfavorable foreign exchange impacts of a weaker Canadian dollar and an inventory draw during the current quarter as a result of lower electricity costs and reduced major project activity.
Operating expense on a dollar and per boe basis decreased for the three and nine months ended September 30, 2015 versus the same periods in 2014 due to a number of cost reduction initiatives undertaken in response to commodity price weakness. These cost reduction initiatives included lower costs on downhole and other activities, lower labour usage and costs, as well as savings from service contract renegotiations.
In addition, on a year-over-year basis, operating expenses further decreased due to the favorable foreign exchange impact of the strengthening of the Canadian dollar versus the Euro and the deferral of costs following a build in crude oil inventory in the year-to-date 2015 period.

General and administration

General and administration expense for Q3 2015 was 10% higher than Q2 2015 and 17% lower than Q3 2014. These fluctuations in general and administration expense for the quarters presented primarily result from variances in the timing of spending, including the timing of allocations from our Corporate segment.
Year-to-date 2015 general and administration expense was 11% lower than the 2014 period due to the impact of a number of cost reduction initiatives undertaken in response to commodity price weakness, including a reduction in third party consultant expenditures.

Other income

Included in the results for the nine months ended September 30, 2015 is a judgment award pertaining to costs incurred as a result of an oil spill at the Ambès oil terminal in France that occurred in 2007. As a result of the award, $31.8 million (before taxes) was recognized as other income.

Current income taxes

Current income taxes in France are applied to taxable income, after eligible deductions, at a statutory rate of 34.4% for 2015. In addition, a 10.7% temporary surtax (as a percentage of the statutory rate) is applicable for tax year 2015 if annual revenue exceeds €250 million. For 2015, the effective rate on current income taxes is expected to be between approximately 13% and 15%. This rate is subject to change in response to commodity price fluctuations, the timing of capital expenditures, and other eligible in-country adjustments.
Q3 2015 current income taxes decreased compared to Q2 2015 and Q3 2014 due to decreased revenues and additional tax deductions taken for depletion.
Current income taxes for the nine months ended September 30, 2015 decreased versus the comparative period in 2014 mainly due to lower funds from operations as a result of the decline in the Dated Brent reference price.

NETHERLANDS BUSINESS UNIT

Overview

Entered the Netherlands in 2004.
Second largest onshore gas producer.
Interests include 16 licenses in the northeast region, five licenses in the central region, and two offshore licenses.
Licenses include more than 800,000 net acres of undeveloped land.
High impact natural gas drilling and development.
Natural gas produced in the Netherlands is priced off the TTF index, which receives a significant premium over North American gas prices.

Operational review

		Three Months Ended			% change		Nine Months Ended		% change
		Sep 30,	Jun 30,	Sep 30,	Q3/15 vs.	Q3/15 vs.	Sep 30,	Sep 30,	2015 vs.
Netherlands business unit		2015	2015	2014	Q2/15	Q3/14	2015	2014	2014
Production
	NGLs (bbls/d)	109	112	63	(3%)	73%	95	76	25%
	Natural gas (mmcf/d)	53.56	32.43	38.07	65%	41%	40.86	40.50	1%
	Total (boe/d)	9,035	5,517	6,407	64%	41%	6,905	6,827	1%
Activity
	Capital expenditures ($M)	5,297	18,885	10,087	(72%)	(47%)	28,515	51,718	(45%)
	Gross wells drilled	-	2.00	1.00			2.00	5.00
	Net wells drilled	-	1.86	0.45			1.86	3.74

Production

Q3 production represented a new record for our Netherlands Business Unit at 9,035 boe/d which is an increase of 64% from the prior quarter. This increase is primarily attributable to placing two wells (Slootdorp-06/07 - 92.8% working interest) on production for an extended production test. These two wells, drilled in the prior quarter, contributed approximately 24 mmcf/d (4,000 boe/d) to the average production rate during the quarter.
Production for Q3 2015 increased by 41%, as compared to Q3 2014 due to the Sloopdorp-06/07 wells. For the year to date period, production was consistent with the prior year as the third quarter production additions from Slootdorp-06/07 were largely offset by the loss of production from our Middenmeer-3 well, which was fully depleted and taken offline in February 2015. The depletion of this well occurred as expected. The turnaround at the Garijp Treatment Centre during Q2 2015 further impacted current year production.
Production in the Netherlands is actively managed to optimize facility use and regulate declines.

Activity review

During Q2, Vermilion drilled two (1.9 net) wells, Slootdorp-06 and Slootdorp-07. These wells are currently on sales during an extended production test to size additional production equipment.
During the quarter, we continued to execute numerous debottlenecking activities to enhance deliverability from the Slootdorp wells.
The Diever-02 exploration well (45% working interest), drilled in 2014, came on production in early November for an extended production test at a gross rate of 28.5 mmcf/d (4,750 boe/d). Because of current pipeline constraints in the multi-well system that Diever-02 produces into, Vermilion's net incremental production increase from this well is limited to approximately 6 mmcf/d (1,000 boe/d), net to Vermilion.

Financial review

		Three Months Ended			% change		Nine Months Ended		% change
Netherlands business unit		Sep 30,	Jun 30,	Sep 30,	Q3/15 vs.	Q3/15 vs.	Sep 30,	Sep 30,	2015 vs.
($M except as indicated)		2015	2015	2014	Q2/15	Q3/14	2015	2014	2014
	Sales	41,083	23,913	26,960	72%	52%	91,814	98,395	(7%)
	Royalties	(638)	(1,294)	(942)	(51%)	(32%)	(2,858)	(3,843)	(26%)
	Operating expense	(5,243)	(5,414)	(5,409)	(3%)	(3%)	(16,483)	(17,841)	(8%)
	General and administration	(2,154)	(454)	(204)	374%	956%	(3,345)	(1,128)	197%
	Current income taxes	(4,487)	(2,347)	(1,189)	91%	277%	(9,222)	(6,278)	47%
	Fund flows from operations	28,561	14,404	19,216	98%	49%	59,906	69,305	(14%)
Netbacks ($/boe)
	Sales	49.42	47.63	45.73	4%	8%	48.70	52.80	(8%)
	Royalties	(0.77)	(2.58)	(1.60)	(70%)	(52%)	(1.52)	(2.06)	(26%)
	Operating expense	(6.31)	(10.78)	(9.18)	(41%)	(31%)	(8.74)	(9.57)	(9%)
	General and administration	(2.59)	(0.90)	(0.35)	188%	640%	(1.77)	(0.61)	190%
	Current income taxes	(5.40)	(4.67)	(2.02)	16%	167%	(4.89)	(3.37)	45%
	Fund flows from operations netback	34.35	28.70	32.58	20%	5%	31.78	37.19	(15%)
Reference prices
	TTF ($/GJ)	8.04	7.94	7.26	1%	11%	8.08	8.41	(4%)
	TTF (€/GJ)	5.52	5.84	5.04	(5%)	10%	5.76	5.68	1%

Sales

The price of our natural gas in the Netherlands is based on the TTF day-ahead index, as determined on the Title Transfer Facility Virtual Trading Point operated by Dutch TSO Gas Transport Services, plus various fees. GasTerra, a state owned entity, continues to purchase all of the natural gas we produce in the Netherlands.
Sales per boe increased by 4% quarter-over-quarter, consistent with a slight increase in the Canadian dollar equivalent TTF reference price. This increase in sales per boe combined with a 64% increase in production resulted in a 72% increase in sales.
On a year-over-year basis, sales per boe increased by 8% and decreased by 8% for the three and nine months ended September 30, 2015, respectively, consistent with movements in the Canadian dollar equivalent of the TTF reference price for the respective periods. For the three months ended September 30, 2015, the 11% increase in the Canadian dollar equivalent of the TTF reference price was coupled with a 41% increase in production, resulting in a 52% increase in sales. For the nine months ended September 30, 2015, a 4% decrease in the Canadian dollar equivalent of the TTF reference price was combined with consistent production volumes, resulting in a 7% decrease in sales.

Royalties

In the Netherlands, we pay overriding royalties on certain wells associated with an acquisition completed by the Netherlands business unit in October 2013. As such, fluctuations in royalty expense in the periods presented relate to the amount of production from those wells subject to overriding royalties.

Transportation expense

Our production in the Netherlands is not subject to transportation expense as gas is sold at the plant gate.

Operating expense

Operating expense on a dollar basis decreased slightly for Q3 2015 versus both Q2 2015 and Q3 2014 primarily as a result of the timing of expenditures. These slight decreases, coupled with significantly higher production from our Slootdorp-06 and Slootdorp-07 wells, resulted in a 41% decrease in operating expense per boe quarter-over-quarter (31% year-over-year).
On a year-to-date basis, operating expense on a dollar and per boe basis decreased approximately 8% due to the favorable foreign exchange impact of a stronger Canadian dollar coupled with reduced facility operation expenditures following cost reduction initiatives undertaken in response to commodity price weakness.

General and administration

Variances in general and administration expense generally relate to timing of expenditures, including the timing of allocations from Vermilion's Corporate segment.

Current income taxes

Current income taxes in the Netherlands apply to taxable income after eligible deductions at a statutory tax rate of approximately 46%. For 2015, the effective rate on current taxes is expected to be between approximately 11% and 13%. This rate is subject to change in response to commodity price fluctuations, the timing of capital expenditures, and other eligible in-country adjustments.
Current income taxes in Q3 2015 were higher compared to Q2 2015 and Q3 2014 due to increased revenues and accelerated tax deductions recognized in 2014.
Current income taxes for the nine months ended September 30, 2015 were higher compared to 2014 as decreased revenues in 2015 were offset with accelerated tax deductions recognized in 2014.

GERMANY BUSINESS UNIT

Overview

Vermilion entered Germany in February 2014.
Holds a 25% interest in a four partner consortium. Associated assets include four gas producing fields spanning 11 production licenses as well as an exploration license in surrounding fields. Total license area comprises 204,000 gross acres, of which 85% is in the exploration license.
Entered into a farm-in agreement in Q3 2015 that will provide Vermilion with participating interest in 19 onshore exploration licenses in northwest Germany, comprising approximately 850,000 net undeveloped acres of oil and natural gas rights. Vermilion will assume operatorship for 11 of the 19 licenses during the exploration phase. The farm-in agreement is expected to close around year-end.

Operational review

		Three Months Ended			% change		Nine Months Ended		% change
		Sep 30,	Jun 30,	Sep 30,	Q3/15 vs.	Q3/15 vs.	Sep 30,	Sep 30,	2015 vs.
Germany business unit		2015	2015	2014	Q2/15	Q3/14	2015	2014	2014
Production
	Natural gas (mmcf/d)	14.00	16.18	15.38	(13%)	(9%)	15.65	14.07	11%
	Total (boe/d)	2,333	2,696	2,563	(13%)	(9%)	2,608	2,345	11%
Activity
	Capital expenditures ($M)	1,605	3,231	1,358	(50%)	18%	5,804	2,184	166%
	Acquisitions ($M)	-	-	-			-	172,871
	Gross wells drilled	-	1.00	-			1.00	-
	Net wells drilled	-	0.25	-			0.25	-

Production

Q3 2015 production of 2,333 boe/d represented a decrease of 13% quarter-over-quarter and a decrease of 9% year-over-year due to a planned maintenance shutdown during the quarter. Year-to-date production increased 11% versus prior year, due to 2014 volumes only reflecting production from the acquisition's effective date of February 1, 2014.

Activity review

The Burgmoor Z3a sidetrack well (25% working interest), which was completed in Q2 2015, was tied-in and placed on production in Q3 2015.

Financial review

		Three Months Ended			% change		Nine Months Ended		% change
Germany business unit		Sep 30,	Jun 30,	Sep 30,	Q3/15 vs.	Q3/15 vs.	Sep 30,	Sep 30,	2015 vs.
($M except as indicated)		2015	2015	2014	Q2/15	Q3/14	2015	2014	2014
	Sales	9,523	10,626	8,591	(10%)	11%	31,544	28,603	10%
	Royalties	(1,477)	(2,238)	(2,046)	(34%)	(28%)	(5,313)	(6,132)	(13%)
	Transportation expense	(627)	(1,240)	(675)	(49%)	(7%)	(2,761)	(2,149)	28%
	Operating expense	(2,796)	(1,373)	(2,227)	104%	26%	(6,168)	(5,824)	6%
	General and administration	(1,311)	(1,435)	(1,090)	(9%)	20%	(4,354)	(2,488)	75%
	Current income taxes	-	-	(146)	-	(100%)	-	(1,189)	(100%)
	Fund flows from operations	3,312	4,340	2,407	(24%)	38%	12,948	10,821	20%
Netbacks ($/boe)
	Sales	44.36	43.31	36.43	2%	22%	44.30	44.68	(1%)
	Royalties	(6.88)	(9.12)	(8.68)	(25%)	(21%)	(7.46)	(9.58)	(22%)
	Transportation expense	(2.92)	(5.05)	(2.86)	(42%)	2%	(3.88)	(3.36)	15%
	Operating expense	(13.03)	(5.60)	(9.44)	133%	38%	(8.66)	(9.10)	(5%)
	General and administration	(6.11)	(5.85)	(4.62)	4%	32%	(6.12)	(3.89)	57%
	Current income taxes	-	-	(0.62)	-	(100%)	-	(1.86)	(100%)
	Fund flows from operations netback	15.42	17.69	10.21	(13%)	51%	18.18	16.89	8%
Reference prices
	TTF ($/GJ)	8.04	7.94	7.26	1%	11%	8.08	8.41	(4%)
	TTF (€/GJ)	5.52	5.84	5.04	(5%)	10%	5.76	5.68	1%

Sales

The price of our natural gas in Germany is based on the TTF month-ahead index, as determined on the Title Transfer Facility Virtual Trading Point operated by Dutch TSO Gas Transport Services, plus various fees.
The 10% decrease in sales quarter-over-quarter is due to a 13% decrease in production, partially offset by a 2% increase in sales per boe, consistent with a slight increase in the Canadian dollar equivalent of the TTF reference price.
On a year-over-year basis, sales per boe increased by 22% and declined by 1% for the three and nine months ended September 30, 2015, respectively, consistent with movements in the Canadian dollar equivalent of the TTF reference price in the respective periods. For the three months ended September 30, 2015, the increase in sales per boe was partially offset by a 9% decrease in production, resulting in an 11% increase in sales. For the nine months ended September 30, 2015, production increased by 11% which, coupled with consistent sales per boe, resulted in a 10% increase in sales.

Royalties

Our production in Germany is subject to state and private royalties on sales after certain eligible deductions. As a percentage of sales, royalties are expected to range from 15% to 20% in 2015.
Q3 2015 royalties as a percentage of sales of 15.5% were lower than the 21.1% for Q2 2015 due to adjustments for prior period royalties recorded in the second quarter. Year-to-date royalties as a percentage of sales of 16.8% were lower than the 21.4% for the comparable periods in 2014 as a result of lower state royalty rates for 2015.

Transportation expense

Transportation expense in Germany relates to costs incurred to deliver natural gas from the processing facility to the customer.
Q3 2015 transportation expense was lower than Q2 2015 due to final adjustments for 2014 recorded in the second quarter. Year-to-date transportation expense was higher than the comparable period in 2014 due to the aforementioned adjustments and the inclusion of only eight months of expense in 2014 due to the timing of our Germany acquisition.

Operating expense

Operating expenses for Germany are billed monthly by the joint venture operator and primarily relate to tariffs charged for facility operations and gas processing.
Q3 2015 had higher operating expense versus both Q2 2015 and Q3 2014 due to a higher level of project activity during the current quarter. Year-to-date operating expense was higher on a dollar basis than the comparable period in 2014 due to the inclusion of only eight months of expense in 2014 due to the timing of our Germany acquisition.

General and administration

General and administration expense increased quarter-over-quarter and year-over-year due to staffing and expenditures relating to our Germany farm-in agreement.

Current income taxes

Current income taxes in Germany apply to taxable income after eligible deductions at a statutory tax rate of approximately 24%. As a function of tax pools in Germany, Vermilion does not presently pay taxes in Germany.

IRELAND BUSINESS UNIT

Overview

18.5% non-operating interest in the offshore Corrib gas field located approximately 83 km off the northwest coast of Ireland.
Project comprises six offshore wells, offshore and onshore sales and transportation pipeline segments as well as a natural gas processing facility.
Corrib is expected to produce approximately 58 mmcf/d (9,700 boe/d) net to Vermilion at peak production rates.

Operational and financial review

		Three Months Ended			% change		Nine Months Ended		% change
Ireland business unit		Sep 30,	Jun 30,	Sep 30,	Q3/15 vs.	Q3/15 vs.	Sep 30,	Sep 30,	2015 vs.
($M)		2015	2015	2014	Q2/15	Q3/14	2015	2014	2014
	Transportation expense	(1,766)	(1,648)	(1,515)	7%	17%	(5,107)	(4,674)	9%
	General and administration	(663)	(628)	(334)	6%	99%	(1,803)	(868)	108%
	Fund flows from operations	(2,429)	(2,276)	(1,849)	7%	31%	(6,910)	(5,542)	25%
Activity
	Capital expenditures	20,694	20,267	30,050	2%	(31%)	53,916	73,507	(27%)

Activity review

On September 1, 2015, the operator, Shell E&P Ireland Limited declared the project ready for service.
On October 8, 2015, the Irish Environmental Protection Agency issued its final determination in support of the Corrib Industrial Emissions License.
Prior to commencing gas production, receipt of Ministerial Consent is required from Ireland's Department of Communications, Environment, and Natural Resources.
Following first gas production, expected in approximately mid-Q4 2015, volumes at Corrib are expected to rise over a period of approximately six months to a peak rate of approximately 58 mmcf/d (9,700 boe/d) net to Vermilion by mid-2016.

Transportation expense

Transportation expense in Ireland relates to payments under a ship or pay agreement related to the Corrib project.

AUSTRALIA BUSINESS UNIT

Overview

Entered Australia in 2005.
Hold a 100% operated working interest in the Wandoo field, located approximately 80 km offshore on the northwest shelf of Australia.
Production is operated from two off-shore platforms, and originates from 21 producing well bores.
Wells that utilize horizontal legs (ranging in length from 500 to 3,000 plus metres) are located 600 metres below the seabed in approximately 55 metres of water depth.
Contracted crude oil production is priced with reference to Dated Brent.

Operational review

Three Months Ended

% change

Nine Months Ended

% change

Sep 30,

Jun 30,

Sep 30,

Q3/15 vs.

Sep 30,

2015 vs.

Australia business unit

2015

2014

Q2/15

Q3/14

2015

2014

Production

Crude oil (bbls/d)

6,433

5,865

6,567

10%

(2%)

5,993

6,718

(11%)

Inventory (mbbls)

Opening crude oil inventory

156

318

189

130

Crude oil production

592

534

604

1,636

1,834

Crude oil sales

(576)

(696)

(535)

(1,501)

(1,706)

Closing crude oil inventory

172

156

258

172

258

Activity

Capital expenditures ($M)

7,966

6,468

15,985

23%

(50%)

20,889

32,667

(36%)

Production

Quarterly production increased 10% quarter-over-quarter and decreased 2% year-over-year. Production volumes are managed within corporate targets while meeting customer demands and the requirements of long-term supply agreements.
We continue to plan for long-term production levels of between 6,000 and 8,000 bbls/d.

Activity review

In Q3 2015, efforts were largely focused on maintenance work, facilities enhancement and preparations for the 2015 drilling program.
The horizontal sidetrack drill program commenced in early October after the arrival of the drilling rig at the Wandoo A platform in late September. Vermilion expects that the well will be completed and placed on production during the fourth quarter.
Additional 2015 planned activities include ongoing facilities maintenance, enhancement, and refurbishment.

Financial review

		Three Months Ended			% change		Nine Months Ended		% change
Australia business unit		Sep 30,	Jun 30,	Sep 30,	Q3/15 vs.	Q3/15 vs.	Sep 30,	Sep 30,	2015 vs.
($M except as indicated)		2015	2015	2014	Q2/15	Q3/14	2015	2014	2014
	Sales	39,325	56,204	63,708	(30%)	(38%)	114,813	212,510	(46%)
	Operating expense	(13,766)	(18,083)	(14,302)	(24%)	(4%)	(37,735)	(43,713)	(14%)
	General and administration	(1,391)	(1,141)	(1,378)	22%	1%	(3,986)	(4,245)	(6%)
	PRRT	(99)	(3,371)	(13,834)	(97%)	(99%)	(5,824)	(46,772)	(88%)
	Corporate income taxes	(2,720)	(5,134)	(5,148)	(47%)	(47%)	(8,431)	(19,678)	(57%)
	Fund flows from operations	21,349	28,475	29,046	(25%)	(26%)	58,837	98,102	(40%)
Netbacks ($/boe)
	Sales	68.20	80.87	119.07	(16%)	(43%)	76.46	124.59	(39%)
	Operating expense	(23.87)	(26.02)	(26.73)	(8%)	(11%)	(25.13)	(25.63)	(2%)
	General and administration	(2.41)	(1.64)	(2.58)	47%	(7%)	(2.65)	(2.49)	6%
	PRRT	(0.17)	(4.85)	(25.86)	(96%)	(99%)	(3.88)	(27.42)	(86%)
	Corporate income taxes	(4.72)	(7.39)	(9.62)	(36%)	(51%)	(5.61)	(11.54)	(51%)
	Fund flows from operations netback	37.03	40.97	54.28	(10%)	(32%)	39.19	57.51	(32%)
Reference prices
	Dated Brent (US $/bbl)	50.26	61.92	101.85	(19%)	(51%)	55.39	106.57	(48%)
	Dated Brent ($/bbl)	65.81	76.12	110.95	(14%)	(41%)	69.79	116.63	(40%)

Sales

Crude oil in Australia is priced with reference to Dated Brent.
During Q3 2015, inventory increased by 16,000 bbls, compared to a draw of 162,000 bbls in Q2 2015 and a build of 69,000 bbls in Q3 2014.
Sales per boe decreased 16% in Q3 2015 versus Q2 2015, consistent with a 14% decrease in the Canadian dollar equivalent of the Dated Brent reference price. This decrease in sales per boe, combined with a decrease in sales volumes due to the absence of a significant inventory draw in the period, resulted in a 30% decrease in sales.
On a year-over-year basis, sales per boe decreased by 43% and 39% for the three and nine months ended September 30, 2015, consistent with a decrease in the Canadian dollar equivalent of the Dated Brent reference price. For the three months ended September 30, 2015, the decline in pricing was slightly offset by higher sold volumes (due to a higher inventory build in the comparative period), resulting in a 38% decrease in sales. For the nine months ended September 30, 2015, the decline in pricing was coupled with a decrease in sold volumes driven by decreased production, resulting in a 46% decrease in sales.

Royalties and transportation expense

Our production in Australia is not subject to royalties or transportation expense as crude oil is sold directly at the Wandoo B platform.

Operating expense

Operating expense decreased in Q3 2015 versus Q2 2015 as a result of a slight build in inventory during the third quarter versus a 162,000 bbl draw in inventory during the second quarter.
Year-over-year, operating expense decreased on both a dollar and per barrel basis largely as the result of savings from cost reduction initiatives, including reduced vessel usage, lower diesel consumption, and reduced staffing costs. These favorable variances were further enhanced by the impact of a weaker Australian dollar in 2015.

General and administration

Fluctuations in general and administration expense for the three and nine months versus the comparable periods were largely a result of the timing of expenditures.

PRRT and corporate income taxes

In Australia, current income taxes include both PRRT and corporate income taxes. PRRT is a profit based tax applied at a rate of 40% on sales less eligible expenditures, including operating expenses and capital expenditures. Corporate income taxes are applied at a rate of 30% on taxable income after eligible deductions, which include PRRT.
For 2015, the combined corporate income tax and PRRT effective rate is expected to be between approximately 15% and 17%. This rate is subject to change in response to commodity price fluctuations, the timing of capital expenditures and other eligible in-country adjustments.
Combined corporate income taxes and PRRT for the three and nine months ended September 30, 2015 were lower than the comparable periods as a result of decreased revenues and increased capital spending in the 2015 periods.

UNITED STATES BUSINESS UNIT

Overview

Entered the United States in September 2014.
Interests include approximately 90,700 acres of land (98% undeveloped) in the Powder River Basin of northeastern Wyoming.
Tight oil development targeting the Turner Sand at a depth of approximately 1,500 metres.

Operational and financial review

		Three Months Ended		% change	Nine Months Ended
United States business unit		Sep 30,	Jun 30,	Q3/15 vs.	Sep 30,
($M except as indicated)		2015	2015	Q2/15	2015
	Sales	1,075	677	59%	2,424
	Royalties	(309)	(191)	62%	(706)
	Operating expense	(146)	(110)	33%	(471)
	General and administration	(896)	(963)	(7%)	(2,939)
	Fund flows from operations	(276)	(587)	(53%)	(1,692)
Netbacks ($/boe)
	Sales	51.60	60.57	(15%)	52.95
	Royalties	(14.83)	(17.08)	(13%)	(15.42)
	Operating expense	(6.98)	(9.88)	(29%)	(10.28)
	General and administration	(43.03)	(86.12)	(50%)	(64.20)
	Fund flows from operations netback	(13.24)	(52.51)	(75%)	(36.95)
Reference prices
	WTI (US $/bbl)	46.43	57.94	(20%)	51.00
	WTI ($/bbl)	60.80	71.23	(15%)	64.26
Production
	Crude oil (bbls/d)	226	123	84%	168
Activity
	Capital expenditures	3,226	2,744	18%	6,607
	Acquisitions	12,785	-		12,785
	Gross wells drilled	-	1.00		-
	Net wells drilled	-	1.00		-

Activity review

Vermilion completed the Seedy Draw North well (100% working interest) in the East Finn prospect area in Q3 2015, which was drilled in Q2 2015.
During the quarter, we consolidated our ownership interest in the eastern Powder River Basin of Wyoming to a 100% working interest through the US $9.6 million acquisition of the remaining 30% interest that was previously outstanding. The acquisition encompassed an estimated 0.9 mmboe of 2P reserves and an additional 22,000 net acres.

Sales

The price of crude oil in the United States is directly linked to WTI, subject to market conditions in the United States.

Royalties

Our production in the United States is subject to federal and private royalties, severance tax, and ad valorem tax. Q3 2015 royalties as a percentage of sales of 28.7% was relatively consistent with Q2 2015 (28.2%).

Operating expense

Operating expense on a dollar basis was higher than the previous quarter due to incremental fuel and electricity purchases for the Seedy Draw North well, which was brought on line at the end of August. As a result of incremental production from this well, operating expense on a per barrel basis decreased quarter-over-quarter from $9.88/boe to $6.98/boe.

General and administration

General and administration expense decreased slightly by 7% quarter-over-quarter due to the timing of expenditures.

CORPORATE

Overview

Our Corporate segment includes costs related to our global hedging program, financing expenses, and general and administration expenses, primarily incurred in Canada and not directly related to the operations of our business units.

Financial review

Three Months Ended

Nine Months Ended

Sep 30,

Jun 30,

Sep 30,

($M)

2015

2014

2015

2014

General and administration recovery (expense)

2,359

500

(2,322)

3,816

(8,647)

Current income taxes

(480)

(547)

(227)

(1,404)

(778)

Interest expense

(15,420)

(14,550)

(12,918)

(43,268)

(36,712)

Realized gain on derivatives

10,854

3,081

8,837

20,192

13,896

Realized foreign exchange gain (loss)

309

(2,740)

812

875

(642)

Realized other income

227

204

235

653

530

Fund flows from operations

(2,151)

(14,052)

(5,583)

(19,136)

(32,353)

General and administration

The increase in the recovery of general and administration costs for the three and nine months ended September 30, 2015 versus the comparable periods in the prior year is due to a decrease in staff-related expenditures, general cost saving initiatives in response to declining crude oil prices, and increased salary allocations to the various business unit segments.

Current income taxes

Taxes in our corporate segment relate to holding companies that pay current taxes in foreign jurisdictions.

Interest expense

The increase in interest expense in Q3 2015 versus the comparable periods in the prior year is primarily due to increased borrowings under our revolving credit facility. The increase in interest expense for the three and nine months ended September 30, 2015 versus the comparable periods in 2014 was further driven by interest expense related to the finance lease recognized in Q1 2015.

Hedging

The nature of our operations results in exposure to fluctuations in commodity prices, interest rates and foreign currency exchange rates. We monitor and, when appropriate, use derivative financial instruments to manage our exposure to these fluctuations. All transactions of this nature entered into are related to an underlying financial position or to future crude oil and natural gas production. We do not use derivative financial instruments for speculative purposes. We have elected not to designate any of our derivative financial instruments as accounting hedges and thus account for changes in fair value in net earnings (loss) at each reporting period. We have not obtained collateral or other security to support our financial derivatives as we review the creditworthiness of our counterparties prior to entering into derivative contracts.
Our hedging philosophy is to hedge solely for the purposes of risk mitigation. Our approach is to hedge centrally to manage our global risk (typically with an outlook of 12 to 18 months) up to 50% of net of royalty volumes through a portfolio of forward collars, swaps, and physical fixed price arrangements.
We believe that our hedging philosophy and approach increases the stability of revenues, cash flows and future dividends while also assisting us in the execution of our capital and development plans.
The realized gain in Q3 2015 related primarily to amounts received on our Dated Brent, WTI, and TTF derivatives, partially offset by payments made on our foreign exchange derivatives.
A listing of derivative positions as at September 30, 2015 is included in "Supplemental Table 2" in this MD&A.

FINANCIAL PERFORMANCE REVIEW

		Three Months Ended
			Sep 30,	Jun 30,	Mar 31,	Dec 31,	Sep 30,	Jun 30,	Mar 31,	Dec 31,
($M except per share)			2015	2015	2015	2014	2014	2014	2014	2013
Petroleum and natural gas sales			245,051	264,331	195,885	306,073	344,688	387,684	381,183	325,108
Net earnings (loss)			(83,310)	6,813	1,275	58,642	53,903	53,993	102,788	101,510
Net earnings (loss) per share
	Basic		(0.76)	0.06	0.01	0.55	0.50	0.51	1.00	1.00
	Diluted		(0.76)	0.06	0.01	0.54	0.50	0.50	0.99	0.98

The following table shows a reconciliation of the change in net earnings (loss):

($M)	Q3/15 vs. Q2/15	Q3/15 vs. Q3/14	2015 vs. 2014
Net earnings - Comparative period	6,813	53,903	210,684
Changes in:
Fund flows from operations	(61)	(68,463)	(239,611)
Equity based compensation	1,113	(2,053)	(4,290)
Unrealized gain or loss on derivative instruments	27,915	24,220	5,941
Unrealized foreign exchange gain or loss	9,927	26,825	28,757
Unrealized other expense	(105)	288	(27)
Accretion	(486)	(135)	139
Depletion and depreciation	(37,697)	(44,684)	(42,433)
Deferred tax	52,271	69,789	108,618
Impairment	(143,000)	(143,000)	(143,000)
Net loss - Current period	(83,310)	(83,310)	(75,222)

The fluctuations in net earnings (loss) from quarter-to-quarter and from year-to-year are caused by changes in both cash and non-cash based income and charges. Cash based items are reflected in fund flows from operations and include: sales, royalties, operating expenses, transportation, general and administration expense, current tax expense, interest expense, realized gains and losses on derivative instruments, and realized foreign exchange gains and losses. Non-cash items include: equity based compensation expense, unrealized gains and losses on derivative instruments, unrealized foreign exchange gains and losses, accretion, depletion and depreciation expense, and deferred taxes. In addition, non-cash items may also include amounts resulting from acquisitions or charges resulting from impairment or impairment recoveries.

Equity based compensation

Equity based compensation expense relates to non-cash compensation expense attributable to long-term incentives granted to directors, officers, and employees under the Vermilion Incentive Plan ("VIP"). The expense is recognized over the vesting period based on the grant date fair value of awards, adjusted for the ultimate number of awards that actually vest as determined by the Company's achievement of performance conditions.

Equity based compensation expense in Q3 2015 was lower than Q2 2015 due to a lower number of awards outstanding. For the three and nine months ended September 30, 2015, equity based compensation expense was higher versus the comparable periods in 2014 due to a higher number of awards outstanding.

Unrealized gain or loss on derivative instruments

Unrealized gain or loss on derivative instruments arise as a result of changes in forecasted future commodity prices. As Vermilion uses derivative instruments to manage the commodity price exposure of our future crude oil and natural gas production, we will normally recognize unrealized gains on derivative instruments when forecasted future commodity prices decline and vice-versa.

For the nine months ended September 30, 2015, we recognized an unrealized gain on derivative instruments of $16.2 million, relating primarily to our TTF, Dated Brent, and WTI swaps and collars. As at September 30, 2015, we have a net derivative asset position of $40.9 million.

Unrealized foreign exchange gain or loss

As a result of Vermilion's international operations, Vermilion conducts business in currencies other than the Canadian dollar and has monetary assets and liabilities (including cash, receivables, payables, derivative assets and liabilities, and intercompany loans) denominated in such currencies. Vermilion's exposure to foreign currencies includes the US dollar, the Euro and the Australian Dollar.

Unrealized foreign exchange gains and losses are the result of translating monetary assets and liabilities held in non-functional currencies to the respective functional currencies of Vermilion and its subsidiaries. Unrealized foreign exchange primarily results from the translation of Euro denominated financial assets. As such, an appreciation in the Euro against the Canadian dollar will result in an unrealized foreign exchange gain, and vice-versa.

For the three and nine months ended September 30, 2015, the Canadian dollar weakened versus the Euro and the US dollar, resulting in an unrealized foreign exchange gain of $15.0 million and $15.1 million, respectively.

Accretion

Fluctuations in accretion expense are primarily the result of changes in discount rates applicable to the balance of asset retirement obligations and additions resulting from drilling and acquisitions.

Q3 2015 accretion expense was relatively consistent with all comparative periods.

Depletion and depreciation

Fluctuations in depletion and depreciation expense are primarily the result of changes in produced crude oil and natural gas volumes.

Depletion and depreciation on a per boe basis for Q3 2015 of $28.28 was higher as compared to $22.98 in Q2 2015. The increase is primarily due to increased production from natural gas properties in the Netherlands which have higher per boe depletion expense. For the three and nine months ended September 30, 2015, depletion and depreciation on a per boe basis increased from $23.21 to $28.28 for the three month period and from $22.92 to $24.62 for the nine month period. These increases were primarily driven by the aforementioned increased production from natural gas properties in the Netherlands, as well as increased light crude oil production from Saskatchewan, Canada which was acquired in April of 2014.

Deferred tax

Deferred tax expense (recovery) arises primarily as a result of changes in the accounting basis and tax basis for capital assets and asset retirement obligations and changes in available tax losses. The increase in deferred tax recovery largely pertains to the tax effect on the $143.0 million impairment charge recorded in Q3 2015 and increased depletion primarily associated with higher global production.

Impairment

FINANCIAL POSITION REVIEW

Balance sheet strategy

We believe that our balance sheet supports our defined growth initiatives and our focus is on managing and maintaining a conservative balance sheet. To ensure that our balance sheet continues to support our defined growth initiatives, we regularly review whether forecasted fund flows from operations is sufficient to finance planned capital expenditures, dividends, and abandonment and reclamation expenditures. To the extent that forecasted fund flows from operations is not expected to be sufficient to fulfill such expenditures, we will evaluate our ability to finance any excess with debt (including borrowing using the unutilized capacity of our existing revolving credit facility) or issue equity.

To ensure that we maintain a conservative balance sheet, we monitor the ratio of net debt to fund flows from operations and typically strive to maintain an internally targeted ratio of approximately 1.0 to 1.3 in a normalized commodity price environment. Where prices trend higher, we may target a lower ratio and conversely, in a lower commodity price environment, the acceptable ratio may be higher. At times, we will use our balance sheet to finance acquisitions and, in these situations, we are prepared to accept a higher ratio in the short term but will implement a strategy to reduce the ratio to acceptable levels within a reasonable period of time, usually considered to be no more than 12 to 24 months. This plan could potentially include an increase in hedging activities, a reduction in capital expenditures, an issuance of equity or the utilization of excess fund flows from operations to reduce outstanding indebtedness.

In the current low commodity price environment, Vermilion's net debt to fund flows ratio is expected to be higher than the longer term target ratio. During this period, Vermilion will remain focused on maintaining a strong balance sheet and will manage its business accordingly.

Long-term debt

Our long-term debt consists of our revolving credit facility and our senior unsecured notes. The applicable annual interest rates and the balances recognized on our balance sheet are as follows:

Annual Interest Rate

As at

Sep 30,

Dec 31,

Sep 30,

Dec 31,

($M)

2015

2014

2015

2014

Revolving credit facility

2.9%

3.1%

1,270,154

1,014,067

Senior unsecured notes ⁽¹⁾

6.5%

224,679

224,013

Long-term debt

3.5%

3.8%

1,494,833

1,238,080

⁽¹⁾The senior unsecured notes, which will mature on February 10, 2016, are included in the current portion of long-term debt as at September 30, 2015.

Revolving Credit Facility

On January 30, 2015, Vermilion increased its credit facility from $1.5 billion to $1.75 billion. During Q2 2015, we negotiated a further expansion and extension of our existing revolving credit facilities from $1.75 billion to $2 billion with a maturity of May 2019. The facility bears interest at rates applicable to demand loans plus applicable margins. The following table outlines the terms of our revolving credit facility:

	As at
		Sep 30,	Dec 31,
		2015	2014
Total facility amount		$2.0 billion	$1.5 billion
Amount drawn		$1.3 billion	$1.0 billion
Letters of credit outstanding		$29.3 million	$8.6 million
Facility maturity date		31-May-19	31-May-17

In addition, the revolving credit facility is subject to the following covenants:

		As at
			Sep 30,	Dec 31,
Financial covenant	Limit		2015	2014
Consolidated total debt to consolidated EBITDA	4.0		2.16	1.21
Consolidated total senior debt to consolidated EBITDA	3.0		1.80	0.99
Consolidated total senior debt to total capitalization	50%		36%	31%

Our covenants include financial measures defined within our revolving credit facility agreement that are not defined under GAAP. These financial measures are defined by our revolving credit facility agreement as follows:

Consolidated total debt: Includes all amounts classified as "Long-term debt", "Current portion of long-term debt", and "Finance lease obligation" on our balance sheet.
Consolidated total senior debt: Defined as consolidated total debt excluding unsecured and subordinated debt.
Consolidated EBITDA: Defined as consolidated net earnings before interest, income taxes, depreciation, accretion and certain other non-cash items.
Total capitalization: Includes all amounts on our balance sheet classified as "Long-term debt", "Current portion of long-term debt", "Finance lease obligation", and "Shareholders' equity".

Vermilion was in compliance with its financial covenants for all periods presented.

Senior Unsecured Notes

We have outstanding senior unsecured notes that are senior unsecured obligations and rank pari passu with all our other present and future unsecured and unsubordinated indebtedness. The following table outlines the terms of these notes:


Total issued and outstanding amount			$225.0 million
Interest rate			6.5% per annum
Issued date			February 10, 2011
Maturity date			February 10, 2016

Vermilion may redeem all or part of the senior unsecured notes at 100% of their principal amount plus any accrued and unpaid interest. The notes were initially recognized at fair value net of transaction costs and are subsequently measured at amortized cost using an effective interest rate of 7.1%.

Net debt

Net debt is reconciled to its most directly comparable GAAP measure, long-term debt, as follows:

	As at
		Sep 30,	Dec 31,
($M)		2015	2014
Long-term debt		1,270,154	1,238,080
Current liabilities ⁽¹⁾		474,885	365,729
Current assets		(381,996)	(338,159)
Net debt		1,363,043	1,265,650

Ratio of net debt to annualized fund flows from operations		2.7	1.6

⁽¹⁾Includes the current portion of long-term debt, which, as at September 30, 2015, represents the senior unsecured notes that will mature on February 10, 2016.

Long term debt, including the current portion, as at September 30, 2015, increased to $1.49 billion from $1.24 billion as at December 31, 2014 as a result of draws on the revolving credit facility during the current year to fund capital expenditures, particularly relating to development expenditures in Canada, Ireland and Australia. The increase in long-term debt resulted in an increase to net debt from $1.27 billion to $1.36 billion. As a result of this increase to long-term debt coupled with weak commodity prices, the ratio of net debt to fund flows from operations increased from 1.6 times as at December 31, 2014 to 2.7 times for the nine months ended September 30, 2015.

Shareholders' capital

During the nine months ended September 30, 2015, we maintained monthly dividends at $0.215 per share and declared dividends which totalled $211.6 million.

The following table outlines our dividend payment history:

Date			Monthly dividend per unit or share
January 2003 to December 2007			$0.170
January 2008 to December 2012			$0.190
January 2013 to December 31, 2013			$0.200
January 2014 to Present			$0.215

Our policy with respect to dividends is to be conservative and maintain a low ratio of dividends to fund flows from operations. During low commodity price cycles, we will initially maintain dividends and allow the ratio to rise. Should low commodity price cycles remain for an extended period of time, we will evaluate the necessity of changing the level of dividends, taking into consideration capital development requirements, debt levels and acquisition opportunities. In a further step to preserve our financial flexibility and conservatively exercise our access to capital, an amendment to our existing DRIP to include a Premium Dividend™ Component was announced in February 2015. The Premium Dividend™ Component, when combined with our continuing Dividend Reinvestment Component, increases our access to the lowest cost sources of equity capital available. While the Premium Dividend™ results in a modest amount of equity issuance, we believe it represents the most prudent approach to preserving near-term balance sheet strength. We view implementation of a Premium Dividend™ as a short-term measure to maintain our financial flexibility while we continue to lower our unit costs and await further clarity on the direction of commodity prices. Both components of our program can be turned off at the company's discretion, offering considerable flexibility. We will actively monitor our ongoing needs and manage our continued use of each component as circumstances dictate.

Although we currently expect to be able to maintain our current dividend, fund flows from operations may not be sufficient during this period to fund cash dividends, capital expenditures and asset retirement obligations. We will evaluate our ability to finance any shortfalls with debt, issuances of equity or by reducing some or all categories of expenditures to ensure that total expenditures do not exceed available funds.

The following table reconciles the change in shareholders' capital:

Shareholders' Capital	Number of Shares ('000s)		Amount ($M)
Balance as at December 31, 2014		107,303	1,959,021
Issuance of shares pursuant to the dividend reinvestment and Premium Dividend^TM plans		2,188	108,269
Vesting of equity based awards		1,158	56,855
Share-settled dividends on vested equity based awards		135	7,561
Shares issued pursuant to the employee savings and bonus plans		34	1,658
Balance as at September 30, 2015		110,818	2,133,364

As at September 30, 2015, there were approximately 1.7 million VIP awards outstanding. As at November 5, 2015, there were approximately 111.2 million common shares issued and outstanding.

ASSET RETIREMENT OBLIGATIONS

As at September 30, 2015, asset retirement obligations were $384.3 million compared to $350.8 million as at December 31, 2014.

The increase in asset retirement obligations is largely attributable to accretion and additions from new wells drilled year-to-date, as well as changes in foreign exchange.

OFF BALANCE SHEET ARRANGEMENTS

We have certain lease agreements that are entered into in the normal course of operations, including operating leases for which no asset or liability value has been assigned to the consolidated balance sheet as at September 30, 2015.

We have not entered into any guarantee or off balance sheet arrangements that would materially impact our financial position or results of operations.

RISK MANAGEMENT

Vermilion is exposed to various market and operational risks. For a detailed discussion of these risks, please see Vermilion's Annual Report for the year ended December 31, 2014.

CRITICAL ACCOUNTING ESTIMATES

The preparation of financial statements in accordance with IFRS requires management to make estimates, judgments and assumptions that affect reported assets, liabilities, revenues and expenses, gains and losses, and disclosures of any possible contingencies. These estimates and assumptions are developed based on the best available information which management believed to be reasonable at the time such estimates and assumptions were made. As such, these assumptions are uncertain at the time estimates are made and could change, resulting in a material impact on Vermilion's consolidated financial statements. Estimates are reviewed by management on an ongoing basis and as a result may change from period to period due to the availability of new information or changes in circumstances. Additionally, as a result of the unique circumstances of each jurisdiction that Vermilion operates in, the critical accounting estimates may affect one or more jurisdictions. There have been no material changes to our critical accounting estimates used in applying accounting policies for the nine months ended September 30, 2015. Further information, including a discussion of critical accounting estimates, can be found in the notes to the Consolidated Financial Statements and annual MD&A for the year ended December 31, 2014, available on SEDAR at www.sedar.com or on Vermilion's website at www.vermilionenergy.com.

INTERNAL CONTROL OVER FINANCIAL REPORTING

There was no change in Vermilion's internal control over financial reporting that occurred during the period covered by this MD&A that has materially affected, or is reasonably likely to materially affect, its internal control over financial reporting.

Supplemental Table 1: Netbacks

The following table includes financial statement information on a per unit basis by business unit. Natural gas sales volumes have been converted on a basis of six thousand cubic feet of natural gas to one barrel of oil equivalent.

	Three Months Ended September 30, 2015				Nine Months Ended September 30, 2015			Three Months Ended September 30, 2014	Nine Months Ended September 30, 2014
		Oil & NGLs	Natural Gas	Total	Oil & NGLs	Natural Gas	Total	Total	Total
		$/bbl	$/mcf	$/boe	$/bbl	$/mcf	$/boe	$/boe	$/boe
Canada
Sales		46.36	2.88	32.78	51.54	2.88	36.34	64.85	68.58
Royalties		(4.72)	(0.10)	(2.81)	(5.30)	(0.05)	(3.09)	(8.89)	(8.05)
Transportation		(2.37)	(0.17)	(1.75)	(2.49)	(0.17)	(1.85)	(1.89)	(1.80)
Operating		(11.37)	(1.44)	(10.10)	(10.31)	(1.41)	(9.50)	(8.91)	(9.17)
Operating netback		27.90	1.17	18.12	33.44	1.25	21.90	45.16	49.56
General and administration				(1.56)			(1.95)	(2.11)	(2.25)
Fund flows from operations netback				16.56			19.95	43.05	47.31
France
Sales		61.75	2.93	60.96	66.26	2.36	65.66	107.99	114.36
Royalties		(6.46)	(0.55)	(6.40)	(6.00)	(0.33)	(5.95)	(7.07)	(7.26)
Transportation		(3.70)	-	(3.64)	(3.38)	-	(3.34)	(4.80)	(4.88)
Operating		(9.62)	(0.95)	(9.55)	(10.57)	(1.04)	(10.52)	(15.42)	(15.80)
Operating netback		41.97	1.43	41.37	46.31	0.99	45.85	80.70	86.42
General and administration				(4.25)			(4.61)	(6.50)	(5.63)
Other income				-			9.57	-	-
Current income taxes				(3.74)			(8.52)	(10.89)	(19.93)
Fund flows from operations netback				33.38			42.29	63.31	60.86
Netherlands
Sales		46.65	8.24	49.42	50.63	8.11	48.70	45.73	52.80
Royalties		-	(0.13)	(0.77)	-	(0.26)	(1.52)	(1.60)	(2.06)
Operating		-	(1.06)	(6.31)	-	(1.48)	(8.74)	(9.18)	(9.57)
Operating netback		46.65	7.05	42.34	50.63	6.37	38.44	34.95	41.17
General and administration				(2.59)			(1.77)	(0.35)	(0.61)
Current income taxes				(5.40)			(4.89)	(2.02)	(3.37)
Fund flows from operations netback				34.35			31.78	32.58	37.19
Germany
Sales		-	7.39	44.36	-	7.38	44.30	36.43	44.68
Royalties		-	(1.15)	(6.88)	-	(1.24)	(7.46)	(8.68)	(9.58)
Transportation		-	(0.49)	(2.92)	-	(0.65)	(3.88)	(2.86)	(3.36)
Operating		-	(2.17)	(13.03)	-	(1.44)	(8.66)	(9.44)	(9.10)
Operating netback		-	3.58	21.53	-	4.05	24.30	15.45	22.64
General and administration				(6.11)			(6.12)	(4.62)	(3.89)
Current income taxes				-			-	(0.62)	(1.86)
Fund flows from operations netback				15.42			18.18	10.21	16.89
Australia
Sales		68.20	-	68.20	76.46	-	76.46	119.07	124.59
Operating		(23.87)	-	(23.87)	(25.13)	-	(25.13)	(26.73)	(25.63)
PRRT⁽¹⁾		(0.17)	-	(0.17)	(3.88)	-	(3.88)	(25.86)	(27.42)
Operating netback		44.16	-	44.16	47.45	-	47.45	66.48	71.54
General and administration				(2.41)			(2.65)	(2.58)	(2.49)
Corporate income taxes				(4.72)			(5.61)	(9.62)	(11.54)
Fund flows from operations netback				37.03			39.19	54.28	57.51
United States
Sales		51.60	-	51.60	52.95	-	52.95	-	-
Royalties		(14.83)	-	(14.83)	(15.42)	-	(15.42)	-	-
Operating		(6.98)	-	(6.98)	(10.28)	-	(10.28)	-	-
Operating netback		29.79	-	29.79	27.25	-	27.25	-	-
General and administration				(43.03)			(64.20)	-	-
Fund flows from operations netback				(13.24)			(36.95)	-	-
Total Company
Sales		56.57	5.36	46.56	61.48	5.18	49.48	76.80	82.73
Realized hedging gain		1.78	0.41	2.06	0.81	0.39	1.42	1.97	1.03
Royalties		(4.59)	(0.22)	(3.25)	(4.68)	(0.27)	(3.48)	(6.46)	(6.09)
Transportation		(2.44)	(0.27)	(2.11)	(2.38)	(0.33)	(2.21)	(2.45)	(2.44)
Operating		(12.94)	(1.36)	(10.99)	(12.96)	(1.44)	(11.25)	(12.53)	(12.81)
PRRT⁽¹⁾		(0.03)	-	(0.02)	(0.67)	-	(0.41)	(3.08)	(3.47)
Operating netback		38.35	3.92	32.25	41.60	3.53	33.55	54.25	58.95
General and administration				(2.49)			(2.89)	(3.62)	(3.60)
Interest expense				(2.93)			(3.04)	(2.88)	(2.73)
Realized foreign exchange gain (loss)				0.06			0.06	0.17	(0.05)
Other income				0.04			2.28	0.05	0.04
Corporate income taxes⁽¹⁾				(2.35)			(3.32)	(3.89)	(6.59)
Fund flows from operations netback				24.58			26.64	44.08	46.02

⁽¹⁾	Vermilion considers Australian PRRT to be an operating item and accordingly has included PRRT in the calculation of operating netbacks. Current income taxes presented above excludes PRRT.

Supplemental Table 2: Hedges

The following tables outline Vermilion's outstanding risk management positions as at September 30, 2015:

	Note	Volume	Strike Price(s)
Crude Oil
WTI - Collar
July 2015 - October 2015	1	250 bbl/d	60.00 - 72.40 US $
July 2015 - December 2015	2	750 bbl/d	75.00 - 82.60 CAD $
July 2015 - December 2015	1	250 bbl/d	61.00 - 69.75 US $
July 2015 - March 2016	3	250 bbl/d	75.00 - 83.45 CAD $
July 2015 - June 2016	4	500 bbl/d	75.50 - 85.08 CAD $
October 2015 - December 2015	3	250 bbl/d	70.00 - 82.95 CAD $
Dated Brent - Collar
July 2015 - October 2015	5	250 bbl/d	65.00 - 74.40 US $
July 2015 - June 2016	6	1,000 bbl/d	80.50 - 93.49 CAD $
July 2015 - June 2016	7	500 bbl/d	64.50 - 75.48 US $
October 2015 - December 2015	8	1,000 bbl/d	79.38 - 92.45 CAD $
October 2015 - June 2016	9	250 bbl/d	82.00 - 94.55 CAD $
January 2016 - June 2016	3	250 bbl/d	84.00 - 93.70 CAD $

North American Natural Gas
AECO - Collar
April 2015 - October 2015		2,500 GJ/d	2.75 - 3.52 CAD $
April 2015 - December 2015		2,500 GJ/d	2.75 - 3.52 CAD $
October 2015 - December 2015		2,500 GJ/d	2.55 - 3.19 CAD $
November 2015 - March 2016		2,500 GJ/d	2.50 - 3.76 CAD $
November 2015 - October 2016		10,000 GJ/d	2.56 - 3.23 CAD $
January 2016 - December 2016		10,000 GJ/d	2.53 - 3.29 CAD $
April 2016 - October 2016		2,500 GJ/d	2.50 - 2.88 CAD $
AECO - Swap
April 2015 - October 2015	10	10,000 GJ/d	2.98 CAD $
April 2015 - December 2015	11	2,500 GJ/d	2.99 CAD $
AECO Basis - Fixed Price Differential
January 2015 - December 2015		5,000 mmbtu/d	Nymex HH less 0.68 US $
April 2015 - October 2015		7,500 mmbtu/d	Nymex HH less 0.62 US $
Nymex HH - Collar
April 2015 - October 2015		10,000 mmbtu/d	3.36 - 4.01 US $
April 2015 - December 2015		2,500 mmbtu/d	3.50 - 4.11 US $
November 2015 - March 2016	12	5,000 mmbtu/d	3.25 - 3.86 US $

⁽¹⁾	The contracted volumes increase to 750 boe/d for any monthly settlement periods above the contracted ceiling price.
⁽²⁾	The contracted volumes increase to 1,500 boe/d for any monthly settlement periods above the contracted ceiling price and is settled on the monthly average price (monthly average US $/bbl multiplied by the Bank of Canada monthly average noon day rate).
⁽³⁾	The contracted volumes increase to 500 boe/d for any monthly settlement periods above the contracted ceiling price and is settled on the monthly average price (monthly average US $/bbl multiplied by the Bank of Canada monthly average noon day rate).
⁽⁴⁾	The contracted volumes increase to 1,250 boe/d for any monthly settlement periods above the contracted ceiling price and is settled on the monthly average price (monthly average US $/bbl multiplied by the Bank of Canada monthly average noon day rate).
⁽⁵⁾	The contracted volumes increase to 500 boe/d for any monthly settlement periods above the contracted ceiling price.
⁽⁶⁾	The contracted volumes increase to 2,500 boe/d for any monthly settlement periods above the contracted ceiling price and is settled on the monthly average price (monthly average US $/bbl multiplied by the Bank of Canada monthly average noon day rate).
⁽⁷⁾	The contracted volumes increase to 1,000 boe/d for any monthly settlement periods above the contracted ceiling price.
⁽⁸⁾	The contracted volumes increase to 2,000 boe/d for any monthly settlement periods above the contracted ceiling price and is settled on the monthly average price (monthly average US $/bbl multiplied by the Bank of Canada monthly average noon day rate).
⁽⁹⁾	The contracted volumes increase to 750 boe/d for any monthly settlement periods above the contracted ceiling price and is settled on the monthly average price (monthly average US $/bbl multiplied by the Bank of Canada monthly average noon day rate).
⁽¹⁰⁾	On the last business day of each month, the counterparty has the option to increase the contracted volumes by an additional 10,000 GJ/d at the contracted price, for the following month.
⁽¹¹⁾	On the last business day of each month, the counterparty has the option to increase the contracted volumes by an additional 2,500 GJ/d at the contracted price, for the following month.
⁽¹²⁾	The contracted volumes increase to 10,000 mmbtu/d for any monthly settlement periods above the contracted ceiling price.

	Note	Volume	Strike Price(s)
European Natural Gas
NBP - Call
October 2016 - March 2017		2,638 GJ/d	4.64 GBP £
NBP - Collar
April 2016 - March 2017		2,638 GJ/d	3.79 - 4.53 GBP £
NBP - Put
April 2016 - September 2016		2,638 GJ/d	3.79 GBP £
NBP - Swap
July 2015 - March 2016		2,592 GJ/d	6.42 EUR €
October 2015 - March 2016		10,368 GJ/d	6.54 EUR €
January 2016 - June 2016		5,184 GJ/d	6.24 EUR €
January 2016 - June 2016		2,592 GJ/d	6.82 US $
July 2016 - March 2017		2,592 GJ/d	5.43 EUR €
TTF - Call
October 2016 - March 2017		2,592 GJ/d	6.03 EUR €
TTF - Collar
January 2015 - December 2015		2,592 GJ/d	6.11 - 6.83 EUR €
January 2016 - December 2016	1	2,592 GJ/d	5.76 - 6.50 EUR €
April 2016 - December 2016	2	12,960 GJ/d	5.58 - 6.21 EUR €
April 2016 - March 2017	3	5,184 GJ/d	5.28 - 6.35 EUR €
July 2016 - December 2016		2,592 GJ/d	5.00 - 5.63 EUR €
July 2016 - March 2017	1	2,592 GJ/d	5.07 - 6.56 EUR €
July 2016 - March 2018	1	2,592 GJ/d	5.32 - 6.54 EUR €
October 2016 - December 2017		2,592 GJ/d	5.00 - 5.89 EUR €
January 2017 - December 2017		2,592 GJ/d	5.00 - 5.63 EUR €
TTF - Put
April 2016 - September 2016		2,592 GJ/d	5.21 EUR €
TTF - Swap
January 2015 - December 2015		11,664 GJ/d	6.45 EUR €
January 2015 - March 2016		5,184 GJ/d	6.40 EUR €
January 2015 - June 2016		2,592 GJ/d	6.07 EUR €
February 2015 - March 2016		5,184 GJ/d	6.24 EUR €
April 2015 - December 2015		2,592 GJ/d	6.30 EUR €
April 2015 - March 2016		5,832 GJ/d	6.18 EUR €
October 2015 - December 2015		2,592 GJ/d	5.69 EUR €
October 2015 - March 2016		2,592 GJ/d	6.64 EUR €
January 2016 - June 2016		5,184 GJ/d	5.94 EUR €
April 2016 - December 2016		2,592 GJ/d	5.91 EUR €
July 2016 - June 2018		2,700 GJ/d	5.58 EUR €
October 2016 - December 2016		2,592 GJ/d	5.45 EUR €

Electricity
AESO - Swap
January 2016 - December 2016		62.4 MWh/d	37.13 CAD $
AESO - Swap (Physical)
January 2013 - December 2015		72.0 MWh/d	53.17 CAD $

US Dollar
USD - Collar
February 2015 - December 2015		2,500,000 US $/month	1.180 - 1.223 CAD $
USD - Forward
February 2015 - December 2015		2,500,000 US $/month	1.198 CAD $

Interest Rate
CDOR to fixed - Swap
September 2015 - September 2019		100,000,000 CAD $/year	1.00 %

⁽¹⁾	The contracted volumes increase to 5,184 GJ/d for any monthly settlement periods above the contracted ceiling price.
⁽²⁾	The contracted volumes increase to 15,552 GJ/d for any monthly settlement periods above the contracted ceiling price.
⁽³⁾	The contracted volumes increase to 10,368 GJ/d for any monthly settlement periods above the contracted ceiling price.

Supplemental Table 3: Capital Expenditures

	Three Months Ended				Nine Months Ended
By classification		Sep 30,	Jun 30,	Sep 30,	Sep 30,	Sep 30,
($M)		2015	2015	2014	2015	2014
Drilling and development		93,381	90,173	180,479	357,865	467,294
Exploration and evaluation		-	-	9,554	-	54,187
Capital expenditures		93,381	90,173	190,033	357,865	521,481
Property acquisition		22,155	480	40,847	22,670	219,074
Corporate acquisition		-	-	-	-	381,139
Acquisitions		22,155	480	40,847	22,670	600,213

	Three Months Ended				Nine Months Ended
By category		Sep 30,	Jun 30,	Sep 30,	Sep 30,	Sep 30,
($M)		2015	2015	2014	2015	2014
Land		763	1,469	2,346	2,974	8,049
Seismic		810	1,723	6,135	4,026	11,436
Drilling and completion		39,712	31,976	93,386	154,031	242,005
Production equipment and facilities		44,589	43,957	68,964	163,301	198,266
Recompletions		3,948	9,288	10,853	20,351	28,538
Other		3,559	1,760	8,349	13,182	33,187
Capital expenditures		93,381	90,173	190,033	357,865	521,481
Acquisitions		22,155	480	40,847	22,670	600,213
Total capital expenditures and acquisitions		115,536	90,653	230,880	380,535	1,121,694

	Three Months Ended				Nine Months Ended
By country		Sep 30,	Jun 30,	Sep 30,	Sep 30,	Sep 30,
($M)		2015	2015	2014	2015	2014
Canada		45,286	22,265	125,276	182,435	663,277
France		17,511	16,793	35,082	68,418	110,663
Netherlands		5,297	18,885	10,087	28,515	51,718
Germany		1,605	3,231	1,358	5,804	175,055
Ireland		20,694	20,267	30,050	53,916	73,507
Australia		7,966	6,468	15,985	20,889	32,667
United States		16,011	2,744	11,175	19,392	11,175
Corporate		1,166	-	1,867	1,166	3,632
Total capital expenditures and acquisitions		115,536	90,653	230,880	380,535	1,121,694

Supplemental Table 4: Production

		Q3/15	Q2/15	Q1/15	Q4/14	Q3/14	Q2/14	Q1/14	Q4/13	Q3/13	Q2/13	Q1/13	Q4/12
Canada
	Crude oil (bbls/d)	9,195	10,182	10,893	11,384	11,469	12,676	9,437	8,719	7,969	8,885	7,966	7,983
	NGLs (bbls/d)	4,513	3,755	2,976	2,741	2,291	2,796	2,071	1,699	1,897	1,725	1,335	1,106
	Natural gas (mmcf/d)	71.94	64.66	61.78	58.36	57.07	57.59	49.53	41.43	43.40	43.69	41.04	31.41
	Total (boe/d)	25,698	24,713	24,165	23,851	23,272	25,070	19,763	17,322	17,099	17,892	16,140	14,323
	% of consolidated	47%	48%	48%	49%	47%	49%	42%	43%	41%	42%	41%	40%
France
	Crude oil (bbls/d)	12,310	12,746	11,463	11,133	11,111	11,025	10,771	11,131	11,625	10,390	10,330	9,843
	Natural gas (mmcf/d)	1.47	1.03	-	-	-	-	-	-	5.23	4.19	4.21	3.91
	Total (boe/d)	12,555	12,917	11,463	11,133	11,111	11,025	10,771	11,131	12,496	11,088	11,032	10,495
	% of consolidated	22%	25%	23%	22%	22%	21%	23%	27%	30%	26%	29%	29%
Netherlands
	NGLs (bbls/d)	109	112	63	81	63	96	69	62	48	50	96	70
	Natural gas (mmcf/d)	53.56	32.43	36.41	31.35	38.07	40.35	43.15	37.53	28.78	38.52	36.91	33.03
	Total (boe/d)	9,035	5,517	6,132	5,306	6,407	6,822	7,260	6,318	4,845	6,470	6,248	5,574
	% of consolidated	16%	11%	12%	11%	13%	13%	16%	15%	12%	15%	16%	15%
Germany
	Natural gas (mmcf/d)	14.00	16.18	16.80	17.71	15.38	16.13	10.64	-	-	-	-	-
	Total (boe/d)	2,333	2,696	2,801	2,952	2,563	2,689	1,773	-	-	-	-	-
	% of consolidated	4%	5%	6%	6%	5%	5%	4%	-	-	-	-	-
Australia
	Crude oil (bbls/d)	6,433	5,865	5,672	6,134	6,567	6,483	7,110	6,189	7,070	7,363	5,287	5,873
	% of consolidated	11%	11%	11%	12%	13%	12%	15%	15%	17%	17%	14%	16%
United States
	Crude oil (bbls/d)	226	123	153	195	-	-	-	-	-	-	-	-
Consolidated
	Crude oil & NGLs (bbls/d)	32,786	32,783	31,220	31,668	31,501	33,076	29,458	27,800	28,609	28,413	25,014	24,875
	% of consolidated	58%	63%	62%	64%	63%	63%	63%	68%	69%	66%	65%	69%
	Natural gas (mmcf/d)	140.97	114.29	115.00	107.42	110.52	114.08	103.32	78.96	77.41	86.40	82.16	68.34
	% of consolidated	42%	37%	38%	36%	37%	37%	37%	32%	31%	34%	35%	31%
	Total (boe/d)	56,280	51,831	50,386	49,571	49,920	52,089	46,677	40,960	41,510	42,813	38,707	36,265

		YTD 2015	2014	2013	2012	2011	2010
Canada
	Crude oil (bbls/d)	10,083	11,248	8,387	7,659	4,701	2,778
	NGLs (bbls/d)	3,754	2,476	1,666	1,232	1,297	1,427
	Natural gas (mmcf/d)	66.16	55.67	42.39	37.50	43.38	43.91
	Total (boe/d)	24,864	23,001	17,117	15,142	13,227	11,524
	% of consolidated	47%	47%	41%	40%	38%	36%
France
	Crude oil (bbls/d)	12,176	11,011	10,873	9,952	8,110	8,347
	Natural gas (mmcf/d)	0.84	-	3.40	3.59	0.95	0.92
	Total (boe/d)	12,316	11,011	11,440	10,550	8,269	8,501
	% of consolidated	23%	22%	28%	28%	23%	26%
Netherlands
	NGLs (bbls/d)	95	77	64	67	58	35
	Natural gas (mmcf/d)	40.86	38.20	35.42	34.11	32.88	28.31
	Total (boe/d)	6,905	6,443	5,967	5,751	5,538	4,753
	% of consolidated	13%	13%	15%	15%	16%	15%
Germany
	Natural gas (mmcf/d)	15.65	14.99	-	-	-	-
	Total (boe/d)	2,608	2,498	-	-	-	-
	% of consolidated	5%	5%	-	-	-	-
Australia
	Crude oil (bbls/d)	5,993	6,571	6,481	6,360	8,168	7,354
	% of consolidated	12%	13%	16%	17%	23%	23%
United States
	Crude oil (bbls/d)	168	49	-	-	-	-
Consolidated
	Crude oil & NGLs (bbls/d)	32,269	31,432	27,471	25,270	22,334	19,941
	% of consolidated	61%	63%	67%	67%	63%	62%
	Natural gas (mmcf/d)	123.51	108.85	81.21	75.20	77.21	73.14
	% of consolidated	39%	37%	33%	33%	37%	38%
	Total (boe/d)	52,854	49,573	41,005	37,803	35,202	32,132

Supplemental Table 5: Segmented Financial Results

	Three Months Ended September 30, 2015
($M)		Canada	France	Netherlands	Germany	Ireland	Australia	United States	Corporate	Total
Drilling and development		37,224	17,369	5,297	1,605	20,694	7,966	3,226	-	93,381
Oil and gas sales to external customers		77,493	76,552	41,083	9,523	-	39,325	1,075	-	245,051
Royalties		(6,638)	(8,038)	(638)	(1,477)	-	-	(309)	-	(17,100)
Revenue from external customers		70,855	68,514	40,445	8,046	-	39,325	766	-	227,951
Transportation expense		(4,131)	(4,566)	-	(627)	(1,766)	-	-	-	(11,090)
Operating expense		(23,877)	(11,998)	(5,243)	(2,796)	-	(13,766)	(146)	-	(57,826)
General and administration		(3,694)	(5,338)	(2,154)	(1,311)	(663)	(1,391)	(896)	2,359	(13,088)
PRRT		-	-	-	-	-	(99)	-	-	(99)
Corporate income taxes		-	(4,696)	(4,487)	-	-	(2,720)	-	(480)	(12,383)
Interest expense		-	-	-	-	-	-	-	(15,420)	(15,420)
Realized gain on derivative instruments		-	-	-	-	-	-	-	10,854	10,854
Realized foreign exchange gain		-	-	-	-	-	-	-	309	309
Realized other income		-	-	-	-	-	-	-	227	227
Fund flows from operations		39,153	41,916	28,561	3,312	(2,429)	21,349	(276)	(2,151)	129,435

	Nine Months Ended September 30, 2015
($M)		Canada	France	Netherlands	Germany	Ireland	Australia	United States	Corporate	Total
Total assets		1,769,222	902,777	219,221	172,664	947,592	223,261	36,955	231,009	4,502,701
Drilling and development		173,954	68,180	28,515	5,804	53,916	20,889	6,607	-	357,865
Oil and gas sales to external customers		246,661	218,011	91,814	31,544	-	114,813	2,424	-	705,267
Royalties		(20,998)	(19,760)	(2,858)	(5,313)	-	-	(706)	-	(49,635)
Revenue from external customers		225,663	198,251	88,956	26,231	-	114,813	1,718	-	655,632
Transportation expense		(12,542)	(11,103)	-	(2,761)	(5,107)	-	-	-	(31,513)
Operating expense		(64,510)	(34,926)	(16,483)	(6,168)	-	(37,735)	(471)	-	(160,293)
General and administration		(13,219)	(15,323)	(3,345)	(4,354)	(1,803)	(3,986)	(2,939)	3,816	(41,153)
PRRT		-	-	-	-	-	(5,824)	-	-	(5,824)
Corporate income taxes		-	(28,293)	(9,222)	-	-	(8,431)	-	(1,404)	(47,350)
Interest expense		-	-	-	-	-	-	-	(43,268)	(43,268)
Realized gain on derivative instruments		-	-	-	-	-	-	-	20,192	20,192
Realized foreign exchange gain		-	-	-	-	-	-	-	875	875
Realized other income		-	31,775	-	-	-	-	-	653	32,428
Fund flows from operations		135,392	140,381	59,906	12,948	(6,910)	58,837	(1,692)	(19,136)	379,726

ADDITIONAL AND NON-GAAP FINANCIAL MEASURES

This MD&A includes references to certain financial measures which do not have standardized meanings prescribed by IFRS. As such, these financial measures are considered additional GAAP or non-GAAP financial measures and therefore may not be comparable with similar measures presented by other issuers.

Fund flows from operations: We define fund flows from operations as cash flows from operating activities before changes in non-cash operating working capital and asset retirement obligations settled. Management believes that by excluding the temporary impact of changes in non-cash operating working capital, fund flows from operations provides a measure of our ability to generate cash (that is not subject to short-term movements in non-cash operating working capital) necessary to pay dividends, repay debt, fund asset retirement obligations and make capital investments. As we have presented fund flows from operations in the "Segmented Information" note of our unaudited condensed consolidated interim financial statements for the three and nine months ended September 30, 2015, we consider fund flows from operations to be an additional GAAP financial measure.

Free cash flow: Represents fund flows from operations in excess of capital expenditures. We consider free cash flow to be a key measure as it is used to determine the funding available for investing and financing activities, including payment of dividends, repayment of long-term debt, reallocation to existing business units, and deployment into new ventures.

Net dividends: We define net dividends as dividends declared less proceeds received for the issuance of shares pursuant to the dividend reinvestment plan. Management monitors net dividends and net dividends as a percentage of fund flows from operations to assess our ability to pay dividends.

Payout: We define payout as net dividends plus drilling and development, exploration and evaluation, dispositions and asset retirement obligations settled. Management uses payout to assess the amount of cash distributed back to shareholders and re-invested in the business for maintaining production and organic growth.
Fund flows from operations (excluding Corrib) and Payout (excluding Corrib): Management excludes expenditures relating to the Corrib project in assessing fund flows from operations (an additional GAAP financial measure) and payout in order to assess our ability to generate cash and finance organic growth from our current producing assets.

Net debt: We define net debt as the sum of long-term debt and working capital. Management uses net debt, and the ratio of net debt to fund flows from operations, to analyze our financial position and leverage. Please refer to the preceding "Net Debt" section for a reconciliation of the net debt non-GAAP financial measure.

Diluted shares outstanding: Is the sum of shares outstanding at the period end plus outstanding awards under the VIP, based on current estimates of future performance factors and forfeiture rates.

Cash dividends per share: Represents cash dividends declared per share.

Netbacks: Per boe and per mcf measures used in the analysis of operational activities.

Total returns: Includes cash dividends per share and the change in Vermilion's share price on the Toronto Stock Exchange.

The following tables reconcile fund flows from operations, net dividends, payout, and diluted shares outstanding to their most directly comparable GAAP measures as presented in our financial statements:

Three Months Ended

Nine Months Ended

Sep 30,

Jun 30,

Sep 30,

($M)

2015

2014

2015

2014

Cash flows from operating activities

122,230

134,668

235,010

279,545

562,840

Changes in non-cash operating working capital

5,082

(6,390)

(41,789)

93,733

46,788

Asset retirement obligations settled

2,123

1,218

4,677

6,448

9,709

Fund flows from operations

129,435

129,496

197,898

379,726

619,337

Expenses related to Corrib

2,429

2,276

1,849

6,910

5,542

Fund flows from operations (excluding Corrib)

131,864

131,772

199,747

386,636

624,879

	Three Months Ended				Nine Months Ended
		Sep 30,	Jun 30,	Sep 30,	Sep 30,	Sep 30,
($M)		2015	2015	2014	2015	2014
Dividends declared		71,244	70,976	68,896	211,610	203,613
Issuance of shares pursuant to the dividend reinvestment and Premium Dividend^TMplans		(44,590)	(42,301)	(20,416)	(108,269)	(58,450)
Net dividends		26,654	28,675	48,480	103,341	145,163
Drilling and development		93,381	90,173	180,479	357,865	467,294
Exploration and evaluation		-	-	9,554	-	54,187
Asset retirement obligations settled		2,123	1,218	4,677	6,448	9,709
Payout		122,158	120,066	243,190	467,654	676,353
Corrib drilling and development		(20,694)	(20,267)	(30,050)	(53,916)	(73,507)
Payout (excluding Corrib)		101,464	99,799	213,140	413,738	602,846

	As at
		Sep 30,	Jun 30,	Sep 30,
('000s of shares)		2015	2015	2014
Shares outstanding		110,818	109,806	106,921
Potential shares issuable pursuant to the VIP		2,825	2,820	2,828
Diluted shares outstanding		113,643	112,626	109,749

CONSOLIDATED BALANCE SHEETS
(THOUSANDS OF CANADIAN DOLLARS, UNAUDITED)

	September 30,			December 31,
		Note	2015		2014
ASSETS
Current
Cash and cash equivalents			148,816		120,405
Accounts receivable			158,375		171,820
Crude oil inventory			17,451		9,510
Derivative instruments			39,418		23,391
Prepaid expenses			17,936		13,033
			381,996		338,159

Derivative instruments			3,580		1,403
Deferred taxes			181,767		154,816
Exploration and evaluation assets		3	311,851		380,621
Capital assets		2	3,623,507		3,511,092
			4,502,701		4,386,091

LIABILITIES
Current
Accounts payable and accrued liabilities			204,326		298,196
Current portion of long-term debt		5	224,679		-
Dividends payable		6	23,825		23,070
Derivative instruments			2,049		-
Income taxes payable			20,006		44,463
			474,885		365,729

Long-term debt		5	1,270,154		1,238,080
Finance lease obligation		2	24,648		-
Asset retirement obligations		4	384,269		350,753
Deferred taxes			362,931		410,183
			2,516,887		2,364,745

SHAREHOLDERS' EQUITY
Shareholders' capital		6	2,133,364		1,959,021
Contributed surplus			87,374		92,188
Accumulated other comprehensive income			95,054		5,722
Deficit			(329,978)		(35,585)
			1,985,814		2,021,346
			4,502,701		4,386,091

CONSOLIDATED STATEMENTS OF NET EARNINGS (LOSS) AND COMPREHENSIVE INCOME
(THOUSANDS OF CANADIAN DOLLARS, EXCEPT SHARE AND PER SHARE AMOUNTS, UNAUDITED)

Three Months Ended

Nine Months Ended

Sep 30,

Note

2015

2014

2015

2014

REVENUE

Petroleum and natural gas sales

245,051

344,688

705,267

1,113,555

Royalties

(17,100)

(29,000)

(49,635)

(82,037)

Petroleum and natural gas revenue

227,951

315,688

655,632

1,031,518

EXPENSES

Operating

57,826

56,227

160,293

172,426

Transportation

11,090

10,979

31,513

32,872

Equity based compensation

16,773

14,720

53,699

49,409

Gain on derivative instruments

(42,874)

(16,637)

(36,347)

(24,110)

Interest expense

15,420

12,918

43,268

36,712

General and administration

13,088

16,262

41,153

48,491

Foreign exchange (gain) loss

(15,267)

11,055

(16,019)

14,255

Other expense (income)

362

(31,654)

217

Accretion

6,199

6,064

17,587

17,726

Depletion and depreciation

2, 3

148,843

104,159

350,946

308,513

Impairment

2, 3

143,000

354,180

216,109

757,439

656,511

EARNINGS (LOSS) BEFORE INCOME TAXES

(126,229)

99,579

(101,807)

375,007

INCOME TAXES

Deferred

(55,401)

14,388

(79,759)

28,859

Current

12,482

31,288

53,174

135,464

(42,919)

45,676

(26,585)

164,323

NET EARNINGS (LOSS)

(83,310)

53,903

(75,222)

210,684

OTHER COMPREHENSIVE INCOME (LOSS)

Currency translation adjustments

101,923

(36,143)

89,332

(33,402)

COMPREHENSIVE INCOME

18,613

17,760

14,110

177,282

NET EARNINGS (LOSS) PER SHARE

Basic

(0.76)

0.50

(0.69)

2.01

Diluted

(0.76)

0.50

(0.69)

1.98

WEIGHTED AVERAGE SHARES OUTSTANDING ('000s)

Basic

110,293

106,768

109,052

104,891

Diluted

110,293

108,290

109,052

106,582

CONSOLIDATED STATEMENTS OF CASH FLOWS
(THOUSANDS OF CANADIAN DOLLARS, UNAUDITED)

			Three Months Ended		Nine Months Ended
			Sep 30,	Sep 30,	Sep 30,	Sep 30,
		Note	2015	2014	2015	2014
OPERATING
Net earnings (loss)			(83,310)	53,903	(75,222)	210,684
Adjustments:
	Accretion	4	6,199	6,064	17,587	17,726
	Depletion and depreciation	2, 3	148,843	104,159	350,946	308,513
	Impairment	2, 3	143,000	-	143,000	-
	Unrealized gain on derivative instruments		(32,020)	(7,800)	(16,155)	(10,214)
	Equity based compensation	7	16,773	14,720	53,699	49,409
	Unrealized foreign exchange (gain) loss		(14,958)	11,867	(15,144)	13,613
	Unrealized other expense		309	597	774	747
	Deferred taxes		(55,401)	14,388	(79,759)	28,859
Asset retirement obligations settled		4	(2,123)	(4,677)	(6,448)	(9,709)
Changes in non-cash operating working capital			(5,082)	41,789	(93,733)	(46,788)
Cash flows from operating activities			122,230	235,010	279,545	562,840

INVESTING
Drilling and development		2	(93,381)	(180,479)	(357,865)	(467,294)
Exploration and evaluation		3	-	(9,554)	-	(54,187)
Property acquisitions		2, 3	(22,155)	(40,847)	(22,670)	(219,074)
Corporate acquisitions, net of cash acquired			-	-	-	(176,179)
Changes in non-cash investing working capital			646	24,539	(26,516)	40,002
Cash flows used in investing activities			(114,890)	(206,341)	(407,051)	(876,732)

FINANCING
Increase (decrease) in long-term debt			63,328	(1,600)	251,189	204,127
Decrease in finance lease obligation			(1,297)	-	(1,297)	-
Cash dividends			(26,437)	(48,415)	(102,586)	(142,600)
Cash flows from (used in) financing activities			35,594	(50,015)	147,306	61,527
Foreign exchange gain (loss) on cash held in foreign currencies			7,844	(1,631)	8,611	5,326

Net change in cash and cash equivalents			50,778	(22,977)	28,411	(247,039)
Cash and cash equivalents, beginning of period			98,038	165,497	120,405	389,559
Cash and cash equivalents, end of period			148,816	142,520	148,816	142,520

Supplementary information for operating activities - cash payments
	Interest paid		18,464	15,132	49,219	40,947
	Income taxes paid		19,501	28,617	78,329	106,177

CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS' EQUITY
(THOUSANDS OF CANADIAN DOLLARS, UNAUDITED)

					Accumulated
					Other		Total
			Shareholders'	Contributed	Comprehensive		Shareholders'
		Note	Capital	Surplus	Income	Deficit	Equity
Balances as at January 1, 2014			1,618,443	75,427	47,142	(24,637)	1,716,375
Net earnings			-	-	-	210,684	210,684
Currency translation adjustments			-	-	(33,402)	-	(33,402)
Equity based compensation expense			-	48,688	-	-	48,688
Dividends declared		6	-	-	-	(203,613)	(203,613)
Shares issued pursuant to the
	dividend reinvestment plan	6	58,450	-	-	-	58,450
Shares issued pursuant to
	corporate acquisition		204,960	-	-	-	204,960
Modification of equity based awards			-	(2,395)	-	-	(2,395)
Vesting of equity based awards		6, 7	47,657	(47,657)	-	-	-
Share-settled dividends
	on vested equity based awards	6, 7	7,519	-	-	(7,519)	-
Shares issued pursuant to the bonus plan		6	721	-	-	-	721
Balances as at September 30, 2014			1,937,750	74,063	13,740	(25,085)	2,000,468

					Accumulated
					Other		Total
			Shareholders'	Contributed	Comprehensive		Shareholders'
		Note	Capital	Surplus	Income	Deficit	Equity
Balances as at January 1, 2015			1,959,021	92,188	5,722	(35,585)	2,021,346
Net loss			-	-	-	(75,222)	(75,222)
Currency translation adjustments			-	-	89,332	-	89,332
Equity based compensation expense		7	-	52,041	-	-	52,041
Dividends declared		6	-	-	-	(211,610)	(211,610)
Shares issued pursuant to the
	dividend reinvestment and Premium
	Dividend^TM plans	6	108,269	-	-	-	108,269
Vesting of equity based awards		6, 7	56,855	(56,855)	-	-	-
Share-settled dividends
	on vested equity based awards	6, 7	7,561	-	-	(7,561)	-
Shares issued pursuant to the employee
	savings and bonus plans	6	1,658	-	-	-	1,658
Balances as at September 30, 2015			2,133,364	87,374	95,054	(329,978)	1,985,814

DESCRIPTION OF EQUITY RESERVES

Shareholders' capital

Represents the recognized amount for common shares when issued, net of equity issuance costs and deferred taxes.

Contributed surplus

Represents the recognized value of employee awards which are settled in shares. Once vested, the value of the awards is transferred to shareholders' capital.

Accumulated other comprehensive income

Represents the cumulative income and expenses which are not recorded immediately in net earnings and are accumulated until an event triggers recognition in net earnings. The current balance consists of currency translation adjustments resulting from translating financial statements of subsidiaries with a foreign functional currency to Canadian dollars at period-end rates.

Deficit

Represents the cumulative net earnings less distributed earnings of Vermilion Energy Inc.

NOTES TO THE CONDENSED CONSOLIDATED INTERIM FINANCIAL STATEMENTS
FOR THE THREE AND NINE MONTHS ENDED SEPTEMBER 30, 2015 AND 2014
(TABULAR AMOUNTS IN THOUSANDS OF CANADIAN DOLLARS, EXCEPT SHARE AND PER SHARE AMOUNTS, UNAUDITED)

1. BASIS OF PRESENTATION

Vermilion Energy Inc. (the "Company" or "Vermilion") is a corporation governed by the laws of the Province of Alberta and is actively engaged in the business of crude oil and natural gas exploration, development, acquisition and production.

These condensed consolidated interim financial statements are in compliance with IAS 34, "Interim financial reporting" and have been prepared using the same accounting policies and methods of computation as Vermilion's consolidated financial statements for the year ended December 31, 2014.

These condensed consolidated interim financial statements should be read in conjunction with Vermilion's consolidated financial statements for the year ended December 31, 2014, which are contained within Vermilion's Annual Report for the year ended December 31, 2014 and are available on SEDAR at www.sedar.com or on Vermilion's website at www.vermilionenergy.com.

These condensed consolidated interim financial statements were approved and authorized for issuance by the Board of Directors of Vermilion on November 5, 2015.

2. CAPITAL ASSETS

The following table reconciles the change in Vermilion's capital assets:

	Petroleum and	Furniture and	Total
($M)	Natural Gas Assets	Office Equipment	Capital Assets
Balance at January 1, 2014	2,784,634	15,211	2,799,845
Additions	608,709	9,980	618,689
Property acquisitions	176,625	-	176,625
Corporate acquisitions	390,523	-	390,523
Changes in estimate for asset retirement obligations	19,107	-	19,107
Depletion and depreciation	(412,768)	(5,072)	(417,840)
Effect of movements in foreign exchange rates	(75,635)	(222)	(75,857)
Balance at December 31, 2014	3,491,195	19,897	3,511,092
Additions	356,253	1,612	357,865
Property acquisitions	21,504	-	21,504
Changes in estimate for asset retirement obligations	7,638	-	7,638
Depletion and depreciation	(329,729)	(3,288)	(333,017)
Recognition of finance lease obligation	31,028	-	31,028
Impairment	(91,976)	-	(91,976)
Effect of movements in foreign exchange rates	118,822	551	119,373
Balance at September 30, 2015	3,604,735	18,772	3,623,507

As part of the Elkhorn acquisition in April of 2014, Vermilion assumed an agreement for the construction and use of a solution gas facility which was under construction at the time of acquisition. The substance of the arrangement was determined to be a lease and has been classified as a finance lease. The carrying amount of the asset and liability at the commencement date in the first quarter of 2015 was $31.0 million, with the liability being apportioned between current ($3.9 million) and long-term ($27.1 million).

Impairments

On a quarterly basis, Vermilion performs an assessment as to whether any cash generating units ("CGUs") have indicators of impairment. When indicators of impairment are identified, Vermilion assesses the recoverable amount of the applicable CGU based on the higher of the estimated fair value less costs to sell and value in use as at the reporting date. The estimated fair value takes into account the most recent commodity price forecasts, expected production and estimated costs and timing of development.

For the three months ended September 30, 2015, Vermilion recorded an impairment charge of $143.0 million related to the light crude oil play in Saskatchewan, Canada. These impairment charges were a result of declines in the price forecasts for crude oil in Canada which decreased the expected cash flows from the CGU. The recoverable amount was determined using a range of fair value estimates encompassing before-tax discount rates of 8% to 10% for proved and probable reserves and 10% to 15% on resources carried within exploration and evaluation assets.

The following table outlines the forward commodity price estimates that were used in the calculation of recoverable amounts:

	WTI Oil (US $/bbl)	AECO Gas (CDN $/mmbtu)	Blended NGLs (CDN $/bbl)
2016	53.55	3.35	30.78
2017	57.20	3.70	36.62
2018	63.65	3.85	41.38
2019	70.35	4.20	45.95
2020	77.30	4.45	50.68
2021	84.45	4.80	55.84
2022	91.90	5.05	61.02
Average increase thereafter	2.0%	2.0%	2.0%

3. EXPLORATION AND EVALUATION ASSETS

The following table reconciles the change in Vermilion's exploration and evaluation assets:

($M)				Exploration and Evaluation Assets
Balance at January 1, 2014				136,259
Additions				69,035
Changes in estimate for asset retirement obligations				22
Property acquisitions				46,135
Corporate acquisitions				138,264
Depreciation				(5,038)
Effect of movements in foreign exchange rates				(4,056)
Balance at December 31, 2014				380,621
Changes in estimate for asset retirement obligations				(8)
Property acquisitions				1,166
Depreciation				(21,893)
Impairment				(51,024)
Effect of movements in foreign exchange rates				2,989
Balance at September 30, 2015				311,851

4. ASSET RETIREMENT OBLIGATIONS

The following table reconciles the change in Vermilion's asset retirement obligations:

($M)			Asset Retirement Obligations
Balance at January 1, 2014			326,162
Additional obligations recognized			22,565
Changes in estimates for asset retirement obligations			(3,434)
Obligations settled			(15,956)
Accretion			23,913
Changes in discount rates			9,404
Effect of movements in foreign exchange rates			(11,901)
Balance at December 31, 2014			350,753
Additional obligations recognized			3,657
Obligations settled			(6,448)
Accretion			17,587
Changes in discount rates			3,973
Effect of movements in foreign exchange rates			14,747
Balance at September 30, 2015			384,269

5. LONG-TERM DEBT

The following table summarizes Vermilion's outstanding long-term debt:

	As at
($M)		Sept 30, 2015	Dec 31, 2014
Revolving credit facility		1,270,154	1,014,067
Senior unsecured notes ⁽¹⁾		224,679	224,013
Long-term debt		1,494,833	1,238,080


⁽¹⁾	The senior unsecured notes, which will mature on February 10, 2016, are included in the current portion of long-term debt as at September 30, 2015.

Revolving Credit Facility

At September 30, 2015, Vermilion had in place a bank revolving credit facility totalling $2 billion, of which approximately $1.27 billion was drawn. The facility, which matures on May 31, 2019, is fully revolving up to the date of maturity.

The facility is extendable from time to time, but not more than once per year, for a period not longer than four years, at the option of the lenders and upon notice from Vermilion. If no extension is granted by the lenders, the amounts owing pursuant to the facility are due at the maturity date. This facility bears interest at a rate applicable to demand loans plus applicable margins. For the nine months ended September 30, 2015, the interest rate on the revolving credit facility was approximately 3.5% (2014 - 3.1%).

The amount available to Vermilion under this facility is reduced by certain outstanding letters of credit associated with Vermilion's operations totalling $29.3 million as at September 30, 2015 (December 31, 2014 - $8.6 million).

The facility is secured by various fixed and floating charges against the subsidiaries of Vermilion. Under the terms of the facility, Vermilion must maintain:

A ratio of total bank borrowings (defined as consolidated total debt), to consolidated net earnings before interest, income taxes, depreciation, accretion and other certain non-cash items (defined as consolidated EBITDA) of not greater than 4.0.
A ratio of consolidated total senior debt (defined as consolidated total debt excluding unsecured and subordinated debt) to consolidated EBITDA of not greater than 3.0.
A ratio of consolidated total senior debt to total capitalization (defined as amounts classified as "Long-term debt", "Current portion of long-term debt", "Finance lease obligation", and "Shareholders' equity" on the balance sheet) of less than 50%.

As at September 30, 2015, Vermilion was in compliance with all financial covenants.

Senior Unsecured Notes

On February 10, 2011, Vermilion issued $225.0 million of senior unsecured notes at par. The notes bear interest at a rate of 6.5% per annum and will mature on February 10, 2016. As direct senior unsecured obligations of Vermilion, the notes rank pari passu with all other present and future unsecured and unsubordinated indebtedness of the Company. Vermilion may redeem all or part of the senior unsecured notes at 100% of their principal amount plus any accrued and unpaid interest. The notes were initially recognized at fair value net of transaction costs and are subsequently measured at amortized cost using an effective interest rate of 7.1%.

6. SHAREHOLDERS' CAPITAL

The following table reconciles the change in Vermilion's shareholders' capital:

Shareholders' Capital	Number of Shares ('000s)	Amount ($M)
Balance as at January 1, 2014	102,123	1,618,443
Shares issued pursuant to corporate acquisition	2,827	204,960
Shares issued pursuant to the dividend reinvestment plan	1,279	79,430
Vesting of equity based awards	955	47,925
Share-settled dividends on vested equity based awards	108	7,542
Shares issued pursuant to the bonus plan	11	721
Balance as at December 31, 2014	107,303	1,959,021
Shares issued pursuant to the dividend reinvestment and Premium Dividend^TM plans	2,188	108,269
Vesting of equity based awards	1,158	56,855
Share-settled dividends on vested equity based awards	135	7,561
Shares issued pursuant to the employee savings and bonus plans	34	1,658
Balance as at September 30, 2015	110,818	2,133,364

Dividends declared to shareholders for the nine months ended September 30, 2015 were $211.6 million (2014 - $203.6 million).

Subsequent to the end of the period and prior to the condensed consolidated interim financial statements being authorized for issue on November 5, 2015, Vermilion declared dividends totalling $23.9 million or $0.215 per share.

7. EQUITY BASED COMPENSATION

The following table summarizes the number of awards outstanding under the Vermilion Incentive Plan ("VIP"):

	Nine Months	Full Year
Number of Awards ('000s)	2015	2014
Opening balance	1,775	1,665
Granted	595	707
Vested	(587)	(515)
Modified	-	(21)
Forfeited	(65)	(61)
Closing balance	1,718	1,775

The fair value of a VIP award is determined on the grant date at the closing price of Vermilion's common shares on the Toronto Stock Exchange, adjusted by the estimated performance factor that will ultimately be achieved.

8. SEGMENTED INFORMATION

Vermilion has operations in three core areas: North America, Europe, and Australia. Vermilion's operating activities in each country relate solely to the exploration, development and production of petroleum and natural gas. Vermilion has a Corporate head office located in Calgary, Alberta. Costs incurred in the Corporate segment relate to Vermilion's global hedging program and expenses incurred in financing and managing our operating business units.

Vermilion's chief operating decision maker reviews the financial performance of the Company by assessing the fund flows from operations of each country individually. Fund flows from operations provides a measure of each business unit's ability to generate cash (that is not subject to short-term movements in non-cash operating working capital) necessary to pay dividends, fund asset retirement obligations, and make capital investments.

	Three Months Ended September 30, 2015
($M)		Canada	France	Netherlands	Germany	Ireland	Australia	United States	Corporate	Total
Drilling and development		37,224	17,369	5,297	1,605	20,694	7,966	3,226	-	93,381
Oil and gas sales to external customers		77,493	76,552	41,083	9,523	-	39,325	1,075	-	245,051
Royalties		(6,638)	(8,038)	(638)	(1,477)	-	-	(309)	-	(17,100)
Revenue from external customers		70,855	68,514	40,445	8,046	-	39,325	766	-	227,951
Transportation expense		(4,131)	(4,566)	-	(627)	(1,766)	-	-	-	(11,090)
Operating expense		(23,877)	(11,998)	(5,243)	(2,796)	-	(13,766)	(146)	-	(57,826)
General and administration		(3,694)	(5,338)	(2,154)	(1,311)	(663)	(1,391)	(896)	2,359	(13,088)
PRRT		-	-	-	-	-	(99)	-	-	(99)
Corporate income taxes		-	(4,696)	(4,487)	-	-	(2,720)	-	(480)	(12,383)
Interest expense		-	-	-	-	-	-	-	(15,420)	(15,420)
Realized gain on derivative instruments		-	-	-	-	-	-	-	10,854	10,854
Realized foreign exchange gain		-	-	-	-	-	-	-	309	309
Realized other income		-	-	-	-	-	-	-	227	227
Fund flows from operations		39,153	41,916	28,561	3,312	(2,429)	21,349	(276)	(2,151)	129,435


	Three Months Ended September 30, 2014
($M)		Canada	France	Netherlands	Germany	Ireland	Australia	United States	Corporate	Total
Drilling and development		88,116	34,883	10,087	1,358	30,050	15,985	-	-	180,479
Exploration and evaluation		9,277	199	-	-	-	-	-	78	9,554
Oil and gas sales to external customers		138,853	106,576	26,960	8,591	-	63,708	-	-	344,688
Royalties		(19,034)	(6,978)	(942)	(2,046)	-	-	-	-	(29,000)
Revenue from external customers		119,819	99,598	26,018	6,545	-	63,708	-	-	315,688
Transportation expense		(4,048)	(4,741)	-	(675)	(1,515)	-	-	-	(10,979)
Operating expense		(19,074)	(15,215)	(5,409)	(2,227)	-	(14,302)	-	-	(56,227)
General and administration		(4,523)	(6,411)	(204)	(1,090)	(334)	(1,378)	-	(2,322)	(16,262)
PRRT		-	-	-	-	-	(13,834)	-	-	(13,834)
Corporate income taxes		-	(10,744)	(1,189)	(146)	-	(5,148)	-	(227)	(17,454)
Interest expense		-	-	-	-	-	-	-	(12,918)	(12,918)
Realized gain on derivative instruments		-	-	-	-	-	-	-	8,837	8,837
Realized foreign exchange gain		-	-	-	-	-	-	-	812	812
Realized other income		-	-	-	-	-	-	-	235	235
Fund flows from operations		92,174	62,487	19,216	2,407	(1,849)	29,046	-	(5,583)	197,898


	Nine Months Ended September 30, 2015
($M)		Canada	France	Netherlands	Germany	Ireland	Australia	United States	Corporate	Total
Total assets		1,769,222	902,777	219,221	172,664	947,592	223,261	36,955	231,009	4,502,701
Drilling and development		173,954	68,180	28,515	5,804	53,916	20,889	6,607	-	357,865
Oil and gas sales to external customers		246,661	218,011	91,814	31,544	-	114,813	2,424	-	705,267
Royalties		(20,998)	(19,760)	(2,858)	(5,313)	-	-	(706)	-	(49,635)
Revenue from external customers		225,663	198,251	88,956	26,231	-	114,813	1,718	-	655,632
Transportation expense		(12,542)	(11,103)	-	(2,761)	(5,107)	-	-	-	(31,513)
Operating expense		(64,510)	(34,926)	(16,483)	(6,168)	-	(37,735)	(471)	-	(160,293)
General and administration		(13,219)	(15,323)	(3,345)	(4,354)	(1,803)	(3,986)	(2,939)	3,816	(41,153)
PRRT		-	-	-	-	-	(5,824)	-	-	(5,824)
Corporate income taxes		-	(28,293)	(9,222)	-	-	(8,431)	-	(1,404)	(47,350)
Interest expense		-	-	-	-	-	-	-	(43,268)	(43,268)
Realized gain on derivative instruments		-	-	-	-	-	-	-	20,192	20,192
Realized foreign exchange gain		-	-	-	-	-	-	-	875	875
Realized other income		-	31,775	-	-	-	-	-	653	32,428
Fund flows from operations		135,392	140,381	59,906	12,948	(6,910)	58,837	(1,692)	(19,136)	379,726


	Nine Months Ended September 30, 2014
($M)		Canada	France	Netherlands	Germany	Ireland	Australia	United States	Corporate	Total
Total assets		1,857,012	894,060	237,070	164,025	809,296	269,959	-	206,305	4,437,727
Drilling and development		215,860	99,564	43,512	2,184	73,507	32,667	-	-	467,294
Exploration and evaluation		33,440	11,099	8,206	-	-	-	-	1,442	54,187
Oil and gas sales to external customers		425,294	348,753	98,395	28,603	-	212,510	-	-	1,113,555
Royalties		(49,937)	(22,125)	(3,843)	(6,132)	-	-	-	-	(82,037)
Revenue from external customers		375,357	326,628	94,552	22,471	-	212,510	-	-	1,031,518
Transportation expense		(11,170)	(14,879)	-	(2,149)	(4,674)	-	-	-	(32,872)
Operating expense		(56,863)	(48,185)	(17,841)	(5,824)	-	(43,713)	-	-	(172,426)
General and administration		(13,951)	(17,164)	(1,128)	(2,488)	(868)	(4,245)	-	(8,647)	(48,491)
PRRT		-	-	-	-	-	(46,772)	-	-	(46,772)
Corporate income taxes		-	(60,769)	(6,278)	(1,189)	-	(19,678)	-	(778)	(88,692)
Interest expense		-	-	-	-	-	-	-	(36,712)	(36,712)
Realized gain on derivative instruments		-	-	-	-	-	-	-	13,896	13,896
Realized foreign exchange loss		-	-	-	-	-	-	-	(642)	(642)
Realized other income		-	-	-	-	-	-	-	530	530
Fund flows from operations		293,373	185,631	69,305	10,821	(5,542)	98,102	-	(32,353)	619,337

Reconciliation of fund flows from operations to net earnings (loss)

Three Months Ended

Nine Months Ended

Sep 30,

($M)

2015

2014

2015

2014

Fund flows from operations

129,435

197,898

379,726

619,337

Equity based compensation

(16,773)

(14,720)

(53,699)

(49,409)

Unrealized gain on derivative instruments

32,020

7,800

16,155

10,214

Unrealized foreign exchange gain (loss)

14,958

(11,867)

15,144

(13,613)

Unrealized other expense

(309)

(597)

(774)

(747)

Accretion

(6,199)

(6,064)

(17,587)

(17,726)

Depletion and depreciation

(148,843)

(104,159)

(350,946)

(308,513)

Deferred taxes

55,401

(14,388)

79,759

(28,859)

Impairment

(143,000)

Net earnings (loss)

(83,310)

53,903

(75,222)

210,684

9. CAPITAL DISCLOSURES

Three Months Ended

Nine Months Ended

($M except as indicated)

Sep 30, 2015

Sep 30, 2014

Sep 30, 2015

Sep 30, 2014

Long-term debt

1,270,154

1,198,648

1,270,154

1,198,648

Current liabilities ⁽¹⁾

474,885

431,175

474,885

431,175

Current assets

(381,996)

(386,385)

(381,996)

(386,385)

Net debt [1]

1,363,043

1,243,438

1,363,043

1,243,438

Cash flows from operating activities

122,230

235,010

279,545

562,840

Changes in non-cash operating working capital

5,082

(41,789)

93,733

46,788

Asset retirement obligations settled

2,123

4,677

6,448

9,709

Fund flows from operations

129,435

197,898

379,726

619,337

Annualized fund flows from operations [2]

517,740

791,592

506,301

825,783

Ratio of net debt to annualized fund flows from operations ([1] ÷ [2])

2.6

1.6

2.7

1.5

⁽¹⁾

Includes the current portion of long-term debt, which, as at September 30, 2015, represents the senior unsecured notes that will mature on February 10, 2016.

Long-term debt, including the current portion, as at September 30, 2015 increased to $1.49 billion from $1.24 billion as at December 31, 2014, primarily as a result of draws on the revolving credit facility to fund capital expenditures as fund flows from operations for the nine months ended September 30, 2015 were lower due to weakening crude oil and North American natural gas prices. The increase in long-term debt resulted in an increase in net debt from $1.27 billion as at December 31, 2015 to $1.36 billion.

Driven primarily by the weakness in crude oil prices, the ratio of net debt to fund flows from operations increased to 2.7 for the nine months ended September 30, 2015.

10. FINANCIAL INSTRUMENTS

Classification of Financial Instruments

The following table summarizes information relating to Vermilion's financial instruments as at September 30, 2015 and December 31, 2014:

As at Sep 30, 2015

As at Dec 31, 2014

Class of financial
instrument

Consolidated balance
sheet caption

Accounting
designation

Related caption on Statement of Net
Earnings (Loss)

Carrying
value ($M)

Fair value
($M)

Carrying
value ($M)

Fair value
($M)

Fair value
measurement
hierarchy

Cash

Cash and cash
equivalents

HFT

Gains and losses on foreign exchange
are included in foreign exchange (gain)
loss

148,816

120,405

Level 1

Receivables

Accounts receivable

LAR

Gains and losses on foreign exchange
are included in foreign exchange (gain)
loss and impairments are recognized as
general and administration expense

158,375

171,820

Not applicable

Derivative assets

Derivative instruments

HFT

Gain on derivative instruments

42,998

24,794

Level 2

Derivative liabilities

Derivative instruments

HFT

Gain on derivative instruments

(2,049)

Level 2

Payables

Accounts payable and
accrued liabilities

OTH

Gains and losses on foreign exchange
are included in foreign exchange (gain)
loss

(228,151)

(321,266)

Not applicable

Dividends payable

Long-term debt

OTH

Interest expense

(1,494,833)

(1,494,592)

(1,238,080)

(1,238,505)

Level 2

The accounting designations used in the above table refer to the following:

HFT - Classified as "Held for trading" in accordance with International Accounting Standard 39 "Financial Instruments: Recognition and Measurement". These financial assets and liabilities are carried at fair value on the consolidated balance sheets with associated gains and losses reflected in net earnings (loss).

LAR - "Loans and receivables" are initially recognized at fair value and are subsequently measured at amortized cost. Impairments and foreign exchange gains and losses are recognized in net earnings (loss).

OTH - "Other financial liabilities" are initially recognized at fair value net of transaction costs directly attributable to the issuance of the instrument and subsequently are measured at amortized cost. Interest is recognized in net earnings (loss) using the effective interest method. Foreign exchange gains and losses are recognized in net earnings (loss).

Level 1 - Fair value measurement is determined by reference to unadjusted quoted prices in active markets for identical assets or liabilities.

Level 2 - Fair value measurement is determined based on inputs other than unadjusted quoted prices that are observable, either directly or indirectly.

Level 3 - Fair value measurement is based on inputs for the asset or liability that are not based on observable market data.

Determination of Fair Values

The level in the fair value hierarchy into which the fair value measurements are categorized is determined on the basis of the lowest level input that is significant to the fair value measurement. Transfers between levels on the fair value hierarchy are deemed to have occurred at the end of the reporting period.

Fair values for derivative assets and derivative liabilities are determined using pricing models incorporating future prices that are based on assumptions which are supported by prices from observable market transactions and are adjusted for credit risk.

The carrying value of receivables approximate their fair value due to their short maturities.

The carrying value of long-term debt outstanding on the revolving credit facility approximates its fair value due to the use of short-term borrowing instruments at market rates of interest.

The fair value of the senior unsecured notes changes in response to changes in the market rates of interest payable on similar instruments and was determined with reference to prevailing market rates for such instruments.

Nature and Extent of Risks Arising from Financial Instruments

Market risk:

Vermilion's financial instruments are exposed to currency risk related to changes in foreign currency denominated financial instruments and commodity price risk related to outstanding derivative positions. The following table summarizes what the impact on comprehensive income before tax would be for the nine months ended September 30, 2015 given changes in the relevant risk variables that Vermilion considers were reasonably possible at the balance sheet date. The impact on comprehensive income before tax associated with changes in these risk variables for assets and liabilities that are not considered financial instruments are excluded from this analysis. This analysis does not attempt to reflect any interdependencies between the relevant risk variables.

	Before tax effect on comprehensive
	income - increase (decrease)
Risk ($M)	Description of change in risk variable	September 30, 2015
Currency risk - Euro to Canadian	Increase in strength of the Canadian dollar against the Euro by 5% over the relevant closing rates		(3,254)

	Decrease in strength of the Canadian dollar against the Euro by 5% over the relevant closing rates		3,254

Currency risk - US $ to Canadian	Increase in strength of the Canadian dollar against the US $ by 5% over the relevant closing rates		(7,014)

	Decrease in strength of the Canadian dollar against the US $ by 5% over the relevant closing rates		7,014

Commodity price risk	Increase in relevant oil reference price within option pricing models used to determine		(5,929)
	the fair value of financial derivatives by US $5.00/bbl at the relevant valuation dates

	Decrease in relevant oil reference price within option pricing models used to determine		6,053
	the fair value of financial derivatives by US $5.00/bbl at the relevant valuation dates

	Increase in relevant TTF reference price within option pricing models used to determine		(7,995)
	the fair value of financial derivatives by € 0.5/GJ at the relevant valuation dates

	Decrease in relevant TTF reference price within option pricing models used to determine		13,510
	the fair value of financial derivatives by € 0.5/GJ at the relevant valuation dates

Interest rate risk	Increase in average Canadian prime interest rate by 100 basis points during the relevant periods		(7,691)

	Decrease in average Canadian prime interest rate by 100 basis points during the relevant periods		7,691

11. SIGNIFICANT TRANSACTIONS

During Q1 2015, Vermilion was awarded a recovery of costs resulting from an oil spill at the Ambès oil terminal in France that occurred in 2007. The French court awarded Vermilion approximately €25 million (before taxes), of which 50% was due immediately to Vermilion upon posting a surety bond. The payment was received in Q2 2015, with the remainder due upon conclusion of the appeal process. Based on the recent court decision and the conclusions of the expert engaged by the French court, Vermilion is virtually certain that the award will be upheld.

SOURCE Vermilion Energy Inc.

Lorenzo Donadeo, CEO;
Anthony Marino, President & COO;
Curtis W. Hicks, C.A., Executive VP & CFO; and/or
Dean Morrison, Director Investor Relations
TEL (403) 269-4884
IR TOLL FREE 1-866-895-8101
[email protected]
www.vermilionenergy.com

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